Practical guidelines for wellsite coring operations. Three of the key inputs to formation evaluation for effective reservoir development and management are:

• Reservoir geological description
• Log calibration for hydrocarbons in place
• Input to reserves calculation

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The requirements for coring shall be agreed with the Drilling Department. The Programme shall include the follwing:

• the prognosed coring point (TVD - RKB or MD - RKB for deviated well)
• the length of core to be cut
• specifications for the determination of coring
• specifications for determining when coring is complete
• any special coring or packing requirements.

Preparation

The following preparation work shall be undertaken prior to coring.

• Hole shall be conditioned prior to pulling out of the hole.
• Once pulled out,the bit and BHA shall be carefully checked for broken and lost cutters. Unless there is a severe loss of cutters, a junk run shall not be made but the hole shall be circulated after running to bottom before commencing to cut core.
• The last bit pulled shall be carefully checked for gauge. If the bit is more than 1.16in under gauge, consideration shall be given to reaming the hole with a full gauge bit and drilling assembly.

Conventional Coring Procedure

The following generic procedures shall be used to verify the detailed procedures proposed by the Coring Contractor.

1. RUN IN the core assembly slowly into the hole. BEWARE of hanging up in open hole.

2. If reaming is necessary PUMP at maximum allowable rate (determined by the core barrel specification and normal drilling engineering considerations ). DO NOT exceed 30 rpm and MAINTAIN minimal WOB. After reaming a section PULL BACK to check trip the reamed section.

3. TAG the bottom gently with high circulating rate without rotation until the mud weight in is similar to mud weight out. Typical circulating rates shall be:

8.1/2in hole     150 gpm

4. DROP the setting ball and when it seats MEASURE slow circulating rates (SCR’s ). START rotating and RECORD the pressures on and off bottom. If back flow is present before dropping the ball PUMP a heavy slug. Prior to the ball seating SLOW the pump.

5. APPLY starting WOB slowly with additional weight and rpm applied smoothly until the coring rate is maximised. WATCH carefully for any indication of torque increase, ROPdecrease, or pump pressure change.

The Driller shall inform the Drilling Supervisor of any change immediately, as changes shall indicate the following:

A pressure increase during coring shall be due to plugging of the barrel, “O” ringing or plugging of the waterways of the corehead or a change in formation.

If the ROP is simultaneously reduced, the corehead is probably ringed or plugged. Continuation in this condition will seriously damage the corehead.

A decrease in pump pressure and ROP, accompanied by erratic torque readings, indicates jamming of the core. The barrel shall be pulled out of the hole.

6. CUT core until the barrel is full or becomes jammed, the end of the programmed coring interval is reached, or cuttings indicate that the required section is cored.

7. CIRCULATE bottoms up, CONDITION the mud and POOH.

Observations While Coring

• Barrel plugging can be checked by comparing the off-bottom pressure with that recorded prior to coring. If plugging is suspected the barrel shall be pulled out off the hole.
• When making a connection or pulling off bottom, overpull shall be seen as the core catcher grips the core. Pull to a maximum of 2 200 lbs overpull, after allowing for drag. If the core fails to break, start circulating up to the maximum used while coring and hold the overpull until the core breaks.
• Extreme care shall be taken when tripping with a core barrel. Flow checks shall be performed as normal when tripping out of hole, and any deviation from expected hole fill-up volume shall be investigated. When pulling out with a core, do not rotate and attempt at all times to minimise jarring or shock loads. The slips shall be set carefully.
• POOH slowly and watch the well closely as the core barrel is a tight fit in the hole and acts as a piston. Swabbing the well can easily occur.

Oriented Coring

Oriented coring provides the data to determine the amount of dip and direction of tilt of the formations. Due to magnetic interference, orientated coring shall be done more than 65 ft below the shoe and two NMDC’s shall be run above the coring equipment. Additional checks shall be made as follows:

• Identity that the main knife and centre punch are installed in accordance with manufacturer’s drawings.
• Check that the electronic multi-shot survey instruments have sufficient battery life and memory for the duration of the coring and surveying.

Coring Unconsolidated Formations

The following guidelines shall be adhered to:

• In unconsolidated formations, face discharge core heads, fibreglass inner barrels, extended pilot shoes and special core catchers shall be used.
• Circulating rates shall be the minimum required to keep the hole clean and sufficiently cool the corehead. Typical circulating rates are 150 - 200 gpm for 8.1/2in hole.

Sponge Coring

Same as conventional coring but downhole formation fluids are kept at downhole pressure as far as possible. The difference is in the methods of core recovery and packing.

A pre-job safety meeting shall be held before pulling the core barrel through the rotary table to ensure that the Drilling and Service Contractors’ personnel understand the job and potential hazards (eg., trapped pressures and catcher failure).

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Coring operations guidelines. Core samples are taken in order to measure accurately the reservoir parameters in hydrocarbon and water bearing formations, and also for other geological investigation.

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When any of these symptoms arise, come out of the hole immediately as damage may occur to bit and barrel.

Check pump strokes hourly or if pressure changes to determine if the pump is a problem or washout has occurred. When drilling, core pressure will fluctuate by c.200lbs. over and c. 200 lbs. under normal conditions.

This article describes the mains components of the coring assemblies: coring bits, core barels and drillstring.

Coring Bits

• Coring Contractor shall provide a range of diamond coring heads.
• The bit shall be run depending on the previous performance and grading.
• Face discharge core heads shall be used in unconsolidated formations.

Core Barrels

• The length of barrel to be run and the inner barrel requirements shall be based on coring success in offset wells and Petroleum Engineer requirements.
• As few coring runs as possible shall be made and if possible all the core shall be cut in one run.
• Core recovery is greater with a shorter core barrel and a shorter coring run.
• Start cutting core with a 90 ft core barrel. If poor recovery is experienced, consider using a 10 ft core barrel.
• The following shall be checked by the Coring Contractor and verified by the Drilling Supervisor:
  • The make up torque shall be in accordance with manufacturer’s figures.
  • The bearing assembly is free.
  • The inner barrel is straight with minimal corrosion on steel barrels.
  • The inner barrel space out is correct in accordance with manufacturer’s figures.
  • The barrel stabilisers are the correct gauge.
  • The safety joint is clean and properly lubricated.
  • The ball seat is compatible with the ball.

Drillstring

• Drill collar weight shall be calculated to allow the maximum planned WOB plus 20 % extra. Alternately, the two collars above the jars shall be replaced by heavy weight drillpipe and these two collars place below the jars.
• Drillpipe shall be drifted when pulling out the hole for coring to ensure that the ball shall pass through. New pipe added whilst coring shall also be drifted.
• Full gauge stabilisers shall be run at 30 ft and 100 ft above the top core barrel stabiliser.
• Jars shall always be run in the coring/drilling assemblies.

Any special requirements for coring fluids shall be included in the Drilling Programme. The general requirements are described below:

• The mud gradient shall exert an overbalance over the formation pressure of no less than 200 psi.
• The static fluid loss shall be less than 8 cc.
• The viscosity and yield point shall be as low as possible to reduce core erosion.
• The solids content shall be as low as possible to prevent core contamination.
• The mud filtrate salinity and composition shall be as close as possible to that of the formation water.
• Water-based mud shall be properly deoxygenated with an oxygen scavenger.
• No surfactants shall be used in the mud.
• The mud shall be conditioned before pulling out for coring. Any mud losses shall be controlled. LCM shall not be pumped through a core barrel unless absolutely necessary.
• During coringthe mud properties shall not be changed unless absolutely necessary. If changes are to be made to the properties the changes shall be made slowly. There shall be sufficient volume of spare mud which can be added to the system to control the mud properties.

Cores are taken in order to measure accurately the reservoir parameters in hydrocarbon and water bearing formations, and for geological purposes. Whether a conventional steel/aluminium inner barrel coring or fibreglass inner barrel coring technique will be used for a particular well is specified in the drilling or test programme and is based on the expected formation conditions. In certain circumstances it may be necessary to change the technique, e.g. a pay zone may be found to be much more viable than expected.

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Bore Hole Compensated Sonic              BHC

Bridge Plug Setting                                 BP

Calliper                                                  CAL

Calliper (Thru-Tubing)                           TTC

Cement Bond Logging                           CBL

Variable Density Logging                       CBL-VD

Cement Dump Bailer                              DB

Combination Production Logging           PCT

Compensated Neutron Log                    CNL

Customer Instrument Service                  CIS

Depth Determination                              DD

Dipmeter (High Resolution)                    HDT

Bore Hole Geometry Tool                      BGT

Dual Induction Laterolog                        DIL

Dual Laterolog (Simultaneous)               DLL

Explosive Service (Back-off)                 BO

Flowmeter-Continuous                           CFM

Flowmeter-Packer                                  FM

Formation Density Logging                    FDC

Formation Micro Scanner                       FMS

Free Point Indicator                               SIT

Full-Bore Spinner Flowmeter                  FBS

Gamma Ray                                          GR

General Purpose Inclinometry                 GPIT

Gradiomanometer                                  GM

Induction/Electrical Logging                   IES

Induction (Spherically Focused)             ISF

Junk Basket                                          JB

Laterolog                                              L

Lithology Density Log                           LDL

Long Spaced Sonic                               LSS

Micro Laterolog                                     MLL

Microlog Calliper                                   MLC

Micro Spherically focused Log               MSFL

Neutron Logging                                   NL

Production Packer and Retainer Setting  PPS

Proximity Log/Calliper/Microlog             PML

Repeat Formation Tester                        RFT

Seismic Reference Service                    WST

Side Wall Coring (Core Sampler Taker)   CST

Sonic Log                                             BHC

Stratigraphic High resolution Dipmeter    SHDT

Tubular Goods Jet Cutter                       TGC

Temperature

(High Resolution Thermometer)              HRT

Thru Tubing Bridge Plug                        TBT

Thru Tubing Dump Bailer                        TBT-DB

Tubing Gauge                                       TGR

Tubular Goods Jet Cutter                       TGC

Vertical Seismic Profiling                       VSP

The following equipment should be available for stripping over a logging cable:

• Loggers fishing kit (to be supplied by Logging Contractor).
• Additional tension meter with cable tension readout for the Driller.
• 90 m of ¼" rope to control the run of cable going over the top sheave.
• 30 m of ½" rope to hold the lower sheave straight.
• Intercom between Driller and Logging Contractor winch operator. 

1. Preparation

1. To prepare the overshot; Inspect, lubricate and dress the overshot contained on the loggers fishing kit. (The single wicker grapple specified for epoxy or rubber covered heads has one cutting edge, and the grapple for steel heads or bodies has several smaller cutting edges). Check the top end to ensure that the 2 3/16" bushing is in place. This holds the 2 1/4" hexagonal adapter of the lower rope socket, if the cable is dropped at the surface.

2. To prepare the cable for cutting;  Set the cable tension at 1-2 MT above normal hanging weight. Secure the cable clamp (T-bar) to the cable, just above the rotary table; (check that the correct sized bushing is used). Lower the cable until the cable clamp is supported by the rotary table. (Continue slacking off the cable, then cut it at a point 1 1/2 - 2 m from the cable clamp, and secure the ends.

3. To re-rig the derrick; Position the lower sheave to that it does not interfere with drill floor operations, and hang the upper sheave from one of the main derrick (water-table) beams, well above the drill  pipe stand, in such a position that it does not interfere with the travelling block.

4. To prepare the cut and thread assembly;  Fit rope sockets to both ends of the logging cable. It is preferred and safer to fit standard rope sockets, (slip type rope sockets, although they are quickly   fitted have been known to fail). Make up the remainder of the assembly, i.e. spearhead, spearhead overshot, swivel, and sub. Sinker bars may be added to the catcher assembly to provide the necessary weight.

Having rigged the derrick, assembled the rope socket and spearhead overshot to the winch end of the cable, and assembled the rope socket and spearhead to the well end of the cable, carry out a full  test. Latch the spearhead overshot to the spearhead while the cable clamp remains on the cable. Mark the cable adjacent to each rope socket with tape and test the cable with 2.5 MT tension for 1 minute. The well-end of the cable should be passed through the (fishing) overshot before the hex-  adapter is replaced.

5.To thread the cable through the drill pipe; In addition to the regular drilling crew, there should be:

• An experienced winch operator.
• One man at the rotary to engage and release the spear overshot.
• A logging engineer on the drill floor to observe the operation.

2. Going In The Hole

The following is a step by step procedure of running in while stripping over the logging cable.

1. Pick up the first stand of drill pipe and install x-over subs as required.

2. Draw the spearhead overshot up to the derrick man, who can then thread it through the first stand of drill pipe. If the sinker bars make the assembly too stiff to pass the travelling block, the assembly should be fed into each stand before it is picked up.

3. Attach the spearhead overshot to the spearhead and make-up the fishing overshot with chain tongs onto the bottom of the first stand.

4. With tension in the cable, check the operation of the remote tension indicator, then remover the cable clamp.

5. Complete the make-up of the fishing assembly with the rig tongs.

6. Run the first stand into the hole:

• maintain a depth tally,
• maintain the cable tension to 1.0 MT,
• pay close attention to the tension indicator.

7. Install the "C" plate, and slack-off the cable until it is supported by the "C" plate.

• the winch operator should flag his cable to ensure that he can easily return to this exact spot for each stand of drill pipe.

8. Release the spearhead overshot, thread it through the next stand, and re-connect it to the spearhead.

9. Pull tension in the cable and remove the "C" plate. Make up the second stand onto the first and repeat the whole process for each stand. Run in slowly and carefully (according to the points listed in Item 6), thus avoiding the following primary hazards:

• the cable being dropped,
• broken armour wire balling up ahead of the overshot,
• the impact of the overshot on a bridge cutting the cable,
• the cable (if it is not removed from a keyseat) double-backing around the overshot.

Note:  Do not rotate the pipe in the hole.

10.When approaching the depth of the fish, it is good practice to clean out the fishing tool by circulating. Circulation at a bridge, at the fish, or during engagement of the fish is accomplished by hanging the cable spearhead on a bushing in a special circulating sub.

• a) With the spearhead hanging on the "C" plate, thread the circulating sub and adapter sub over  the spearhead overshot. Latch the spearhead overshot onto the spearhead, lift the cable and remove the "C" plate.
• b) Make-up the subs onto the drill-pipe. Place the special bushing over the cable and into the circulating sub. Lower the cable until the rope socket rests on the bushing. Unlatch the spearhead overshot.
• c) Make up the kelly onto the circulating sub, using the appropriate cross-overs.

11.When the overshot is a short distance from the fish, the fish may come free. If this occurs  circulation may be used to clean the overshot and then the logging tool can be pulled into the grapple. The fish may, however, be covered by formation solids, requiring the overshot to be circulated down onto the fishing neck. In this case the overshot must reach the fish with sufficient       tension still in the logging cable to prevent it going slack and looping over the rope socket.

The original tension at surface, including the weight of the logging tool, is known. Also, the elongation (stretch) per 3000 m of standard logging cable sizes with respect to tool weight, can be determined from charts supplied by the Logging Contractor. Thus the fish can be engaged as follows:

• a) Pull on the logging cable with the original logging tension and check the elevation of the spear point.
• b) From the Logging Contractor's chart, find the cable stretch due to the weight of the logging tool in mud.
• c) The elevation minus the stretch gives the elevation of the spear point for neutral tension in the cable at the logging tool. Space out the string with pup joints so that the spear point will not be below this elevation when the overshot engages the fish.

Note:   This procedure cannot be used on floating rigs because of the heave and tide  movements of the rig in relation to the logging tool. In this case, lower the string without circulating over the fish while maintaining a close-to-maximum pull on the logging cable.

If circulating over the fish, continue pumping while lowering the pipe and engaging the fish. An increase in both pump pressure and cable tension should be noted as the tool head enters the overshot. Stop circulating.

12.After proving, by motion of the pipe and its effect on the cable tension, that the fish is engaged, the  cable weak-point may be broken by:

• installing the cable clamp,
• latching the elevators around the cable, (under the cable clamp) and,
• pulling slowly until the weakpoint breaks.

13.Cut the cable to remove the rope sockets, then tie the two ends together with a reef knot. Tape the loose ends onto the logging cable to prevent them hanging up as they pass over the sheaves.

14.Spool the cable onto the winch, then pull the fish out of the hole. Do not rotate because the fish may disengage from the overshot.

3. Problems While Stripping Over The Cable

1. If the spearhead rope socket fails, then a broken cable is left in the hole.

2. If the spearhead with rope socket and cable is accidentally dropped into the pipe, run the thread through overshot with the largest applicable guide down the pipe and attempt to engage the spear. If this fails, the drill pipe can be pulled because the bushing in the fishing overshot will catch the hexagon adapter on the spearhead.

3. When cable tension increases sharply, the cable may be stuck in a keyseat and doubled back outside the overshot. Picking up the pipe should cause a small decrease in tension. Increase the cable tension and the guide should free the cable ahead of the advancing overshot.

4. When cable tension increases moderately fast, a broken armour cable may be balling up at the overshot.

5. If the cable tension increase is gradual, as is normal for a deviated well, the elevation of the spear point will be lower. If the spear point becomes lower than the top of the pipe during running in, a  short length of spacer bar may be introduced between the rope socket and spear head.

6. If a bridge is encountered, it should be removed by circulating.

7. During stripping over operations on floating rigs, the sheave arrangement is not compensated for heave and tide movements. Hence the winch operator has to take extra care to avoid breaking the  weak point prematurely.

4. Logging Tool Stuck In A Cased Hole

In deviated wells (greater than 25 deg) it is almost invariably safer to strip over the cable in order to recover both tool and cable.

In vertical wells it is also preferable to strip over, although in certain circumstances (after consultation with Base) the following fishing procedure may be applied;

1. Secure the cable clamp to the cable just above the rotary table.

2. Re-arrange the sheaves as per item (b) 3.

3. Latch the elevators around the cable, (under the cable clamp), and pull slowly until the weak point breaks.

4. With the logging cable in tension, remove the cable clamp and spool the cable onto the logging unit winch.

5. Rig down wireline and fish for the stuck tool using conventional methods. On retrieval, ensure that the complete tool has been recovered.

5. Fishing Through Tubing

When a tool becomes stuck either in or below tubing, in most cases the only remedy is to pull the tubing to recover the fish.

Reverse circulating to recover the fish may be feasible. Fishing with slick line (piano-wire) could be considered, although this technique can only be successful if the tool is free, (e.g. if it has dropped off the end of the logging cable). Although jarring is possible, fishing for stuck tools using slick-line will almost invariably aggravate the problem.

Stuck logging tools are one of the non-productive time incidents experienced in well operations. Before logging, the Drilling Supervisor shall verify that the hole is in good condition and the well is not live. He shall also record the logging weak-point tension, cable tension limit and tool weight in mud. The Logging Contractor's stretch chart shall be available to verify the pull.

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This article discusses perforating casing with the use of wireline for:

• carrying out remedial casing cementing, by squeezing through perforations and
• for monitoring of (formation) pressures behind the casing.

1  Casing perforation

A meeting should be held prior to rigging up for perforation, with the following staff present:

• Logging Engineer/ Well Site Geologist
• Well Service Supervisor, as applicable
• Wireline Operations Supervisor
• Drilling Supervisor
• Well Site Drilling Engineer

The main purpose of the meeting is to:

• Clarify the reporting and communication lines.
• Discuss the operation.
• Discuss any special circumstances, e.g. weather conditions, hole condition, radio silence, timing, concurrent operations, etc.

In addition a pre-job discussion with the logging and drill crews should be held.

Before the gun is run in the hole, a dummy run is made, to check that the tubing/casing is free from obstructions. The dummy should have the same OD. as the perforating gun to be used. Logging run previously conducted without any obstructions encountered, may be regarded as a dummy run, which under such circumstances may be excluded, subject to discussion with Base.

If pressures are expected to be released during perforation, or if a permeable zone is perforated, a wireline BOP, lubricator and stuffing box shall be rigged up on a wireline riser nippled up on top of the BOP. With the cable head in the lubricator, pressure test the equipment to the required pressure.

Make sure that there are no stray voltages in the cable head, or voltage potential between rig and casing, and also that the wireline unit is properly earthed.

Measure the length of each gun and the distance between first shot and CCL/GR, when assembled.

During all handling of guns, nonessential personnel must be excluded from the work area.

When guns are armed all personnel shall keep out of the line of fire, until the gun is safely in the well.

2  Depth Correlation

Run casing collar locator (CCL) and gamma-ray (GR) logs over the entire interval to be perforated. Record log at perforation depth, and correlate with previously run gamma-ray logs on the reference logs. To ensure that the gun is at the correct depth before shooting, the depth calculations shall independently checked twice, prior to authorise the logging engineer to fire the guns.

During the detonation, observe for indications that gun has fired.

The mud level in the hole should be carefully observed for losses or gains throughout the logging run, and specifically prior to POH. The hole should be kept full at all times.

When the perforating assembly is retrieved, ensure that the gun is in the top of lubricator before closing the wire-line valve.

When the gun is laid out on catwalk it shall be checked for unfired charges.

If a radioactive logging tool sticks in the hole, the following guidelines must be adhered to:

• Do not continue work the tool because this may result in accidentally breaking the weak link.
• The Drilling Supervisor shall provide the Operations Engineer and provide him with all relevant information regarding the position of fish, allowable tension of weak point and cable, etc. The Operations Engineer must inform Head of Operations who shall approve the Fishing Programme which is to be written by the Operations Engineer. The Drilling Supervisor shall ensure that the Logging Engineer informs his management.
• Hold a pre-job safety meeting and emphasise to all personnel the requirement to keep clear of the rig floor during recovery.
• Proceed with strip over operations.
• Circulate bottoms up and have the logging contractor monitor the mud returns with a Gamma Ray tool placed in the return line. Ensure no personnel other than Logging Contractor's to be near mud pits or returns lines.
• Ensure that with the tool engaged in the overshot, circulation remains possible using the circulating sub if necessary.
• Unless authorised otherwise by the Head of Operations reverse stripping shall be carried out as a precaution against dropping the tool.

Recovery of Radioactive Sources

• Until a radioactive source has been fished out of the hole and is back in its carrying shield, try to keep the maximum distance between the source and personnel.
• Keep the number of personnel on the rig floor to an absolute minimum.
• The Driller should pull the tool containing the source as far as possible above the rig floor (minimum 50 ft).
• The rig crew should then cover the hole and leave the rig floor.
• The Driller should leave the rig floor until the Logging Engineer indicates that they are ready to disengage the fish and put the source into the shield.
• The shield should be placed near the spot where the source is to be released from the tool. Care should be taken to handle the source housing at points of minimum radiation, using the source handling tools.
• If the source cannot be removed from the tool, a wrap around shield should be attached to the tool and then taken to the logging base

Abandonment of a Source in the Hole

• Only the Head of Operations can authorise the abandonment of a tool down hole. If the hole is straight, a 1 000 ft cement plug shall be set on top of the tool prior to any other activity taking place. When well is handed over all details of radioactive source abandoned in hole has to be recorded in the handover sheet and metal plate marker installed on wellhead/Xmas tree.
• Ensure governmental legislation is followed

The required equipment (Logging Contractor Fishing Kit) for both Cut and Thread and Reverse Cut and Thread methods are:

•  Bowen overshot kit series 105 (H-131931) with a multiple choice of grapples and guides
• cable hanger kit (H-133930) with different sizes and weights of sinkerbars and at least two cable hangers.
• Rope socket kit (H-133929)
• subs of 4.1/2in API IF for top end of the Overshot Top sub (B-20913) and both ends of the circulating sub (B-20914).
• remote tension meter
• Intercom set
• deployment bars
• 5 ft pup joint of sucker rod if the cable cut was made to low
• 300 ft of 1/4in rope to control the end of the cable going over the top sheave
• 100 ft of 1/2in rope to hold the lower sheave straight.

More fatalities occur during free point indication/ backoff than during any other wire-line operation except perforating.

In Free Point Indication/ Backoff  (FPI/ BO) operations, the travelling block is required for working the drill pipe and consequently the upper sheave has to be installed in the certified, permanent upper sheave support in the Drilling Mast. Precautions such as safety slings and shackle pin locking devices etc. shall be incorporated.

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This article describe the requirements for radioactive sources and explosives (permit to work, transporation, handling and storage).

1. Radioactive Sources

Permit to Work

All operations involving the use of radioactive sources must be performed under the Permit to Work system.

Storage

The radioactive sources must be stored in clearly marked approved storage containers (locked and keys with Drilling Supervisor) on each rig inside their appropriate shields. The storage containers must be fixed by welding, bolting or chains and must be located as far as is practical from regularly occupied working areas. The gamma radiation level at the surface of the container must be no more than 7.5 u Sv per hour. The 7.5 - 2.5 u Sv/hr area around the container shall be marked a “no-stay area”. Barrier stands/signs shall be erected to mark the extent of the controlled area.

Transportation

Sources must be transported in the special storage boxes under police escort. Transportation shall be limited as much as possible. A controlled area shall be established on the transport vessel or vehicle.

Handling

The Logging Engineer, or his designated operator under the Company written instruction, are the only persons permitted to handle radioactive sources at all times. The drilling crew are not permitted to help during this operation. Sources should be returned to the storage container immediately after use.

2. Explosives

Permit to Work

All operations involving the use of explosives must be performed under the Permit to Work system.

Storage

There must be two clearly labelled storage boxes available for primary and secondary explosives respectively. Explosives should only be taken outor transported immediately before use. Explosives storage boxes should be placed on jettison platforms offshore or at easy dump positions.

Handling

The Logging Engineer is the only person who is allowed to arm or disarm any tool using explosives. The red “safety key” must be removed from the logging cab before any arming or disarming operation. The only people permitted on the drill floor when explosive tools are on surface are the Logging Crew, Drilling Supervisor and the Driller. Radio silence is to be maintained during arming/disarming the tools and when tools are less than 500’ from surface in hole.

The Reverse Cut and Thread Method is recommended in case a logging tool containing a radioactive source is stuck and has to be fished.

After this point the procedure deviates from the Cut and Thread Method.

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This article provides cable and weak strength for Schlumberger and Baker Atlas

Logging Cables And Weak Points - Schlumberger

CABLE DIAMETER        WT/FT   BREAK. STRAIN

(INS.)                            (LBS)                (LBS)

_______________________________________________

7 - 46    15/32"               0.330                16,000

7 - 46V  15/32"               0.330                16,700

1 - 22    7/32"                0.080                5,100

CABLE WEAK                       BREAKING STRAIN

POINTS                                                  (LBS)

______________________________________________

Strong                                      5,450 - 6,900

Standard                                   4,800 - 5,400

Deep Well                                 3,500 - 4,400

Note:    For cables that are not new, the breaking strain will be lower than the quoted values. Thus 50% of the new cable     breaking load is the maximum that may be pulled without consulting the Base.

Logging Cables And Weak Points - Atlas Wireline Services

CABLE DIAM.               WT/FT   BREAKING       MAX. REC.

(INS.)                            (LBS)    STRAIN(LBS)    PULL (LBS))

___________________________________________________________

Multi-conductor:

7H464G 15/32"(0.462)      0.343  17,000              11,340

7H314A  5/16"(0.323)       0.181  9,500               6,365

Mono-conductor:

1H220A  7/32"(0.223)       0.093  5,000              3,350

1H181A  3/16"(0.185)       0.064  3,600              2,400

CABLE WEAK   STRANDS         NOMINAL         NORMAL

POINTS                                    STRENGTH       LIMIT(LBS)

___________________________________________________________

Multi-conductor:

7H464G STUD      -                    6,000               3,800

7H314A STUD      -                    3,000                2,000

Mono-conductor:

1H220A CABLE    7                   1,323                  886

1H181A CABLE    6                   1,062                  711

___________________________________________________________

Note:    For cables that are not new, the breaking strain will be lower than the quoted values. Thus 50% of the new cable     breaking load is the maximum that may be pulled without consulting the Base.

Acronyms for Baker Atlas logging tools.

Back-off                                               BO

Bridge Plug                                        BPS

Borehole Compensated Acoustilog

(Norm. Spacing)                               AC

Borehole Compensated Acoustilog

(Long Spacing)                                 ACL

Borehole Geometry Tool

(4 Arm Calliper)                                4CAL

Calliper                                              CAL

Cased Hole Formation Tester      CHFT

Cement Bond Log                           CBLV

Circumferential Borehole Imaging Log    CBIL

Check Shot Survey                          SLS

Compensated Densilog                CDL

Compensated Neutron                  CN

Diplog (Four-Arm High Resolution)         RDIP

Dual Laterolog                                 DLL

Electrical Log                                   EL

Flowmeter                                        CSF

Fluid Density                                         FDL

Formation Multi-tester                            FMT

Formation Tester Cased Hole                 FMTCH

Free Point Indicator                               FPI

Gamma Ray                                          GR

Natural Gamma Ray Spectrosc.             SPL

Induction - Electrical                              IEL

Junk Catcher                                         JB

Laterolog                                              LL

Microlog                                               ML

Microlaterolog                                       MLL

Neutron                                     NL

Photon Log                                           PHT

Proximity Log                                       PL

Pulsed Neutron (Lifetime Log)                NLL

Pulsed Neutron (Dual Detector)              DNLL

Radioactive Tracer                                 RT

Sidewall Samples                                  SWC

Sonic Log                                             AC

Sonic Long Spacing                              ACL

Sound (Sonan) Log                               SNL

Spinner Flolog                                      CSF

Temperature Log                                   TEMP

Thru-tubing Bridge Plug                         TPS

Ultrasonic Dip-Log                                U-DIP

Vertical Seismic Profiling                       VSP

This articles describes the mains guidelines and quality checks to be performed for successful logging operations

1. Preparation prior to logging operations:

• All wireline logging tools shall be checked and tested prior to rigging up.
• Logging operations shall commence when the hole conditions are stable. A check trip shall be required before running the formation pressure/sampling tool if there were hole problems during the previous run.
• The mud specifications shall meet the program specifications. The overbalance shall be at least 200 psi.
• Fishing equipment shall be available at the well site for all logging tools. All dimensions, lengths and connections of all the tools shall be recorded.
• For formation pressure/sampling logging a plot of expected pressures shall be prepared.

2. logging operations guidelines.

• The hole shall be circulated through the trip tank during logging operations. The hole shall be kept full throughout, and the trip tank volume shall be recorded every 15 minutes. The trend shall be monitored whilst running in and pulling out.
• The wireline logging depths shall be set to zero at surface and checked when pulling out to surface. Additional checks shall be made at casing depths and at TD.
• If a tool hangs up while running in and the section has not been logged before, log out of the well. If one of the detectors of a combination tool does not function properly, log the remaining detectors which have not been recorded before. When anticipating poor hole conditions, always log in as well as out of the hole to secure data.
• If a section has to be repeated, a 500 ft section shall be made on each logging run, and a 200 ft overlap with previous logging runs shall be made. The repeat section shall be made across an interval of interest.
• When running a calliper tool in a section where the top of the logged interval is below the casing shoe a 1 000 ft section over the shoe shall be run to check shoe depth and calliper gauge.
• Mud shall be sampled from both the pits and flowline immediately before the end of circulation prior to a logging job for analysis and resistivity measurement. This shall be repeated after check trips if resistivity tools are to be run.
• Check trips to bottom shall be required to ensure the hole and mud conditions.
• The weak-point tension limit and cable tension limit shall be checked and tool weight in mud calculated before entering open hole. Normal logging tension shall be checked every 1 000 ft in open hole. This is especially important in deviated holes where drag can be significant.

3. quality control guidelines

• The depth correlation of all the curves on the log must be checked with each other.
• The repeat section must be checked with the main log for agreement. The curves must be examined to see if they have sensible values. They shall be compared with logs in nearby wells, which must always be available on the rig.
• The correct logging speed must be verified. The speed can be determined from the breaks in the lines at the edges of the log which occur every minute. For example, if the distance is 60 ft, the logging speed was 60 ft/min. For resistivity logs the standard logging speed is 60 ft. Statistical nuclear tools require a speed of 30 ft/min. The acceptable range is +/- 10 %. Confirm this with the Logging Contractor in advance.
• Verification shall be made that there is 200 ft overlap between successive logging runs.
• The depth discrepancies between successive logging runs must be less than 2 ft.
• For the Cement Bond Log, a 300 ft section of the free pipe reading during logging must always be recorded (if uncemented sections exist).

4. Formation Pressure Tests guidelines

• When taking pressures the tool shall initially be set for two minutes only. If the pressure does not build up properly the tool shall be unseated and another attempt made.
• Plot both the formation pressure and mud pressures as they are taken. Inconsistencies in the mud gradient shall be checked immediately (a smooth mud gradient shall be regarded as a quality check).

5. Highly Deviated Wells guidelines

• Before entering open hole the normal logging tension shall be recorded. It shall be higher than that of a vertical hole and large stretch corrections shall be required.
• Checks shall be made to ensure that the tool is moving down the well as the wireline is being run into the hole.
• Short tool combinations are easier to get down the hole particularly in areas of high dogleg.
• For high deviations or particularly difficult holes, consideration shall be given to other techniques, eg., drillpipe (TLC) or coiled tubing (E-line) conveyed logging tools or the use of logging while drilling tools (LWD).

6. Horizontal Wells guidelines

• Horizontal wells shall be logged either with LWD or TLC techniques.
• The use of drilling jars are not recommended because of the risk of logging tool damage. It shall not be possible to run jars or HWDP because of ID restrictions for an extended length. This requires enough regular drillpipe at the well site to replace the HWDP’s, drill collars, jars, etc.
• The running in speed shall not exceed that used when running a packer on drillpipe. Below the kick-off point, the tools shall tend to lie on the low side of the hole and not be subject to so much bouncing as higher up. Obstructions downhole (eg., liner tops) shall be passed with caution. Break circulation at regular intervals (ie., every 10 stands).
• A down log shall be taken while running in. The Logging Contractor procedures shall recommend that the tools do not tag the bottom of the hole but stay a minimum 20ft above drillers depth. Depth control shall be checked with the drillpipe during in-run and out-run.
• Continuous communication is required between Driller and the wireline unit to ensuring the pulling speed and cable spooling speed are matched, and to minimise reaction time if the tool begins to stick. Minimise downward movement when setting slips, because the calliper will be in the open position.
• The cable shall not be slacked off to avoid the risk of damaging it at the side entry sub.
• A cable head tension/compression meter readout shall be made available to the Driller on the rig floor.
• The string to be spaced out to have latch point in cased hole.
• If circulating sub cannot be latched increase cable running speed and check for latching from logging unit.

Prior to any fishing operations ensure that all personnel involved are aware of their duties by means of a pre-operation safety meeting.

Dressing the Tools

Take a new grapple, grapple control and guide and assemble the overshot. Ensure that the correct type and size of grapple is used.

Preparing the Cable

The following procedures should be adhered to when preparing the cable for the cut and thread method:

1. Pull the cable to 2000 lbs above normal tension to remove any slack.

Read more …

Pipe conveyed logging (PCL) logging is performed when conventional wireline operations are not feasible, such as in high angle/horizontal wells.

 If there is doubt as to whether wireline logging will be successful, consideration should be given to mobilising PCL equipment on standby, although the standby cost should be balanced against the likelihood of its required use. Above 70^o inclination (PCL) logging shall be used.

Job Preparation

A successful operation requires obtaining vital well site information before the job.

Basic information that needs to be acquired includes:

casing depth size and weight

liner top (if applicable)

hole size and TD

directional data

mud weight and temperature, mud type, mud additives (nut plug etc.)

drillpipe size, grade, tool connections, ID’s

include drillpipe connections ie., 4.1/2in x H 4.1/2 IF, as well as drillpipe size, 4.1/2in, 5in, etc. so that the internal diameter of the drillpipe is known

use of a top drive on the rig, iron roughnecks or other effect mechanical apparatus that effect the PCL operation should be checked.

Bit Size and Drillpipe

Another major area to be concerned with is small bit size (6in) and small drillpipe, commonly 3.1/2in IF Cable Side Entry Sub.

If 3.1/2in IF drillpipe is run all the way to the surface and a split drillstring is not used, it will require using a small 3.1/2in IF Cable Side Entry Sub

It will not be possible to run jars or heavy weight drillpipes since there are restrictions of 2.1/4in for an extended length.

This will require the rig to have enough regular drillpipe (grade E or 3 ½” tubing - Xover to be available) on location to replace the heavyweights, drill collars, jars, etc. and only normal drillpipe should be run below the Cable Side Entry Sub .

Heavyweight can be shifted in the derrick in order to be run on top of Cable Side Entry Sub

Cable Side Entry Sub shall not be run in open hole.

If a rig is using a tapered drillstring, (ie., 3.1/2in bottom, 4.1/2in on top) the internal diameter of the crossover subs should be checked to make sure they are at least 2.40in ID. It is possible to get through an ID of 2.1/4in but only if it is a short section like a crossover. Any 2.1/4in ID’s need to be physically checked for clearance using a pump-down wet cement head (PWCH) (female connector) or rabbit of the same length.

Tool Checks and Calibrations

The Logging Contractor Engineer shall perform all tool and auxiliary equipment checks and calibration.

The Drilling Supervisor or Operations Engineer shall check tool dimensions and position of each logging tool. It is a requirement to run the AMS and the Drilling Supervisor should check that it has been modified to give a readout range from (-3000 lbs) compression to (+3000 lbs) tension.

Rig Up Considerations

The rig up procedures require a large degree of planning and co-ordination between the Logging Contractor and Drilling Contractor. Overall responsibility for safety rests with the Drilling Supervisor. The Drilling Supervisor shall make a forward plan and conduct an operations and safety meeting prior to rigup.

Initial Trip Downhole

After rig-up the tool string is ready to be run in the hole. The running in speed should not exceed that used when running a packer on drillpipe (one stand per 2 mins) or as recommended by the logging contractor.

Additional considerations are:

• the flexibility of the drillpipe.
• whether the travelling block is on rails or not.
• the kick-off point, (below this depth the tools will tend to lie on the low side of the hole and not be subject to so much bouncing as higher up)
• obstructions downhole, eg., liner tops, (these should be passed with caution)

Continue to RIH to the casing shoe (or top logging interval, if higher). Install the cable side entry sub.

The Drilling Contractor should also have checked there is sufficient stands of drillpipe in the derrick to get to the bottom of the logging interval to avoid stationary connection time in open hole.

Connecting Cable Side Entry Sub to the Drillpipe

The Logging Engineer shall advise the Driller on the correct procedures for this operation.

Running/Pump Down of PWCH and Cable

The Logging Engineer shall supervise running the pump-down wet connector head (PWCH) and cable in the hole. The drillpipe assembly shall clearly record all restrictions, which should be passed with caution.

If it is required to pump down the PWCH, the Logging Engineer shall advise the required pump rates

Preparing for Latching

The Logging Engineer shall supervise the operation and advise on the required pump rates. The outline procedure is to run the PWCH to within +/- 1 m of the male connector. At this point the (pumps are shut down if in use and) cable up weight is checked which also relieves torque build-up, together with distance to the (DWCM) male connector.

After this, the pumps are used to establish additional cable tension (prior to running the PWCH downhole at the required latch speed). Increased cable speed requires additional pump rate to maintain pressure (all to be advised by the Logging Engineer).

After latching, there will be a pressure increase of typically 200 - 300 psi. Pumping should continue until advised by the Wireline Engineer to stop. This is to insure a good mechanical latch.

Tool Latch Verification

The Logging Engineer shall check insulation of cable phases and confirm that there is a good electrical and mechanical latch prior to continuing with the programme.

Running In / Log- In

A slug of heavy mud is pumped either prior to running in or on bottom prior to logging out, to ensure the drillstring is pulled dry.

Continuous voice communication shall be maintained between the Driller and the logging unit, as this will minimise the reaction time required to stop the drillpipe, eg., if the tool string hits an obstruction. One logging contractor personnel with portable radio to stay on rig floor during the entire operation.

A down log should be taken while running in. The Logging Contractor procedures recommend that the tools do not tag the bottom of the hole but stay a minimum 20 ft above drillers depth. Depth control will be checked with the drillpipe which should be checked on in-run and out-run.

Log Out

Continuous communication is required between Driller and the logging unit to ensuring the pulling speed and cable spooling speed are matched, and to minimise reaction time if the tool begins to stick.

After Logging and Rig Down

Once the Cable Side Entry Sub  is within one stand of the drill floor the preparations to unlatch the female connector commence. The exact procedures will be advised by the Logging Engineer and include unlatching the PWCH up to rig down of the Cable Side Entry Sub .

Once the logging tool string is at surface the Logging Engineer shall supervise the rigging down, and report any observations, eg., tool damage, to the Drilling Supervisor immediately on completion.

Logging While Drilling (LWD)

Planning

Formation evaluation whist drilling (LWD) may be included in the Drilling Programme by the Operations Engineer for the following reasons:

• when accurate selection of casing points is required
• to assist in picking core points when justified in terms of time savings for circulating samples
• to guarantee obtaining some log information if hole conditions are very unstable
• to save time and cost against running wireline logs
• to assist in the early identification of hydrocarbons
• to assist in the detection of the on-set of overpressures.

A detailed technical and financial justification is required for using LWD.

Procedures and Reporting

When LWD is specified, full procedural requirements for the preparation and running of tools will be provided by the LWD Contractor. Reporting requirements will be detailed in the Drilling Programme by the Operations Engineer and Petrophysicts.Particular attention must be paid to the procedures for running and removal of nuclear sources.

3. Rig-Up and Survey Quality Control

The checks for rigging up for logging and running the survey are important to achieve a good quality of the surveys to be run. The wireline contractor shall have detailed procedures developed for this purpose. These shall cover activities and services like:

-   Placement and installation of wire-line unit(s).

-   Rigging up of wire-line sheaves.

-   Handling and storage of explosives and radioactive material, and precautions in this respect.

-   Surface preparations, assembly and function testing of logging tools.

-   Running in hole.

-   On bottom checks and considerations.

-   Measures to prevent getting stuck.

-   Surveying.

-   Post Survey activities.

-   Cutting Side Wall Samples.

-   Running and Setting of Packers.

-   Running directional Survey Tools.

-   Reporting.

4. Safety

Good communications are important in order to maintain safety during electric wire-line logging. The following procedures should be observed with regard to the safety of personnel and equipment:

1. The chain connecting the lower sheave shall be securely anchored and the sheave adjusted to  the centre of the well.

2. Keep well clear of the logging cable. If it is stretched tight in the hole and is over tensioned, the cable may break suddenly. If the cable is loose on the deck, it may be that the tool is hung up in the hole and too much cable has been unspooled.

-       Never step over the cable, always walk around it!

3. Check the cable armour regularly for unravelling armour strands. This applies particularly to operations through a stuffing box.

4. Avoid the drill floor area during logging operations.

5. Do not stand close to the lower sheave, in case the tie-down chain breaks or comes undone due to high tension in the cable.

6. Tag a reminder on the BOP control panel to ensure the cable is not cut by inadvertent closure during wire-line operations.

7. Do not perform overhead lifts across or near the cable during wire-line operations.

When the wire-line operations involves the use of explosives and radioactive sources, all operations shall be conducted in accordance with the safety procedures. Only authorised and qualified personnel shall be on the drill floor during these operations, and clear signs and barriers should be placed to show such operations are in progress. The requirement regarding radio silence shall be observed as appropriate.

5. Preparation for Logging

1. Carry out a test transmission to check if the equipment is operational.

2. Ensure that logs of any adjacent or nearby well are available for comparison and correlation.

3. Check the logging programme with the contractor to confirm the running order of the tools. Do not run a tool requiring a radioactive source as first in hole, until bottom hole conditions are known. Run the surveys in decreasing order of importance in case the hole condition deteriorates.

4. Provide the logging contractor with the following data:

a)      Well description, location and drill floor elevation, BOP and Wellhead depths.

b)     Bit and casing sizes, total depth and casing shoe depths, any anomalies in the string.

c)      Mud type, weight, viscosity, water loss and pH.

d)     The logging programme, including;

-           all logs which are required,

-           intervals to be logged, and where repeat sections are to be recorded,

-           which logs are to be taped, and when transmission should be carried out, as applicable.

e)      Downhole conditions relevant to the logging operations; e.g. deviation, tight spots, dog legs, pressure and gas zones, fill experienced on previous trips, etc.

f)      The duration of the last circulation of the hole and the time when circulation stopped prior to pulling out of the hole for logging.

5. Provide a mud sample 1 litre, mud filtrate 10 cc. and mud cake (at least 3/16 in (6 mm) thick to be representative). The mud sample should be taken from the flow line during circulation just prior to logging. Ensure the measurements are made on the sample as soon as possible.

6. Sidewall Samples

Sidewall samples are taken to provide either palaeotological or petrophysical information. The samples are obtained using a tool on a wireline. Because sidewall sampling involves the use of explosives, the following procedures shall be strictly adhered to:

1. All operations shall be conducted in accordance with the safety procedures given above on the use and handling of explosives. Only authorised and qualified personnel shall be on the drill floor during these operations, and clear signs and barriers should be placed to show such operations are in progress. The requirement regarding radio silence shall be observed as appropriate.

2. Check distance from the measure point of correlation tool (S.P. or Gamma Ray) to the bottom shot. Make the appropriate correction before taking the first sample and adjust as the firing proceeds.

3. Ensure the powder load for each shot has been correctly loaded.

4. Ensure that:

a)      The correct size gun is used.

b)     The correct length fasteners are used.

c)      High temperature powder is used when necessary above 140 C, bottom hole temperature.

5. Make the depth correlation log (GR) at the normal gamma ray logging speed of 500 m/hr and   determine the correct depth. Check carefully for creep i.e. the movement of sample taken after the winch has stopped. If the creep is 0.5 m or less, stop at correct firing depth to shoot sample. If creep exceeds 0.5 m, it is permissible to shoot "on the run": in this case, note on the report form that this technique has been used, and in particular report any samples suspected of being shot off   depth.

6. After successfully firing each shot, try to "work" the core free. If all attempts at freeing a core fail, the retaining wires can be broken by dropping the sample taker rapidly and snapping them off.

7. Move up and down slowly 3000 m/hr with the samples. For unconsolidated samples lower speeds should be used e.g. 1200 m/hr.

8. Watch the tension very carefully when entering and ascending through casing.

9. Untangle the retaining wires. Remove one bullet at a time from the gun, starting at the bottom of the gun (Sample no.1). Place the bullets in the correct compartment of the box, (supplied by the Logging Contractor) and continue to remove the other bullets. Once all the bullets have been removed, press each core into a sample bottle one at a time noting the recovery. Record also when bullets are lost or empty. This sample removal/identification should be supervised by the Logging     Engineer and a Company Drilling or Petroleum Engineering representative, to ensure that depth identification of the samples is correct.

10.Ensure that all relevant data i.e. Company name, well number, sample depth, sample number is given on the sample container. Mark the sample number on the container lid.

The sidewall samples shall be described on the Sidewall Sample Report.

These descriptions shall be sent immediately to Base and the samples despatched on the first available helicopter.

7. Running and Setting Packers

Because the running and setting of packers involves the use of explosives, the following procedures shall be strictly adhered to:

1. All operations shall be conducted in accordance with the safety procedures on the use and handling of explosives. Only authorised and qualified personnel shall be on the drill floor during these operations, and clear signs and barriers should be placed to show such operations are in progress. The requirements regarding radio silence shall be observed as appropriate.

2. Keep the packer under cover in a safe place until required.

3. Run the junk catcher until hole is clean. If necessary, make a check trip with a bit and scraper   followed by a further junk catcher run.

4. Inspect the packer carefully (particularly the slips and rubber) and witness the preparation of the packer prior to running in hole. Ensure the correct size packer is used.

5. Avoid running the packers into or through perforated intervals because deformed casing or burred holes may jam the packer or damage the seal rubbers. Do not exceed a running speed of 3000 m/hr. Keep the tension under constant observation, as the plug is a tight fit and may easily hang up on any obstructions.

6. Use a CCL for depth control, and never attempt to set a plug within 1 m of a collar. The normal practice is to check depths when pulling up, to avoid problems with loops or slack cable. However, in large casing sizes, the centralising action of the packer may keep the CCL away from the hole sides so the collars are difficult to locate. In this case it is often possible to see the collars when moving down - when moving upwards subsequently to setting depth, make allowance for hysteresis in the tool movement.

7. Make a CCL log across the setting depth to ensure correlation with GR/CCL survey.

8. Record at a distance of two or three casing collars below setting depth, then stop at required depth.

9. Set packer. Observe the tension change or cable vibration. Up to three distinct tension kicks may be observed when setting a packer. Allow at least one minute after firing for the packer to fully set   before carefully pulling back the setting tool. For large packers, a longer time may be required.

10.Move the CCL across the scale, record two casing collars above setting depth. Pull up slowly to ensure the tool has disengaged from the packer.

11.After setting a bridge plug, lower the setting tool on to the plug, record the pick-up point and two collars above. This procedure should not be followed with production packers (cement retainers) in case the tool latches on to the packer and cannot be freed.

Note:The pick up point may appear deeper due to reduced cable stretch as the weight of the plug will no longer be applied to the cable.

12.Ensure the plug has set correctly, but do not exceed 3000 m/hr when pulling out. If the plug has NOT set, pull out much more slowly, particularly if there are indications that only one set of slips may have operated.

13.Keep unnecessary personnel off rig floor while gas pressure is released from the setting tool.

14.Check the setting tool carefully to ensure that its operation was normal, i.e. the release stud has sheared, and there is no damage to the release sleeve. If there is any doubt that the packer has set correctly, run slim-hole CCL (1 11/16") to determine packer depth.

8. Formation Testing

Basically there are six stages to formation testing operations:

-   Surface preparation

-   Running in the hole

-   Pretests

-   Sampling

-   Transfer of samples

-   Reporting of results

and the procedures and guidelines for each are given in the article on production testing.

9. Pipe Conveyed Logging

9.1 Pipe Conveyed Logging/ Logging Through Drillpipe

-   Two systems are available for use:

1. Push Down Systems TLC/PCL. These systems use regular open hole logging tools run down hole on 3 1/2" or 5 1/2" Drillpipe (Schlumberger/Western Atlas).

2. Pump Down Systems. These systems pumps down slim hole logging tools (2 3/4" or 1 11/16") through drillpipe ( Western Altas).

The two systems are usable in any well where wireline run logging tools are unable to pass, such as bad hole section/wash out or where hole deviation is too high.

The preplanning of a TLC/PCL operation require planning of tool combination, selection of and organisation of special tools based on well data.

Drilling jar will be run if required .Special precautions shall be taken when a drilling jar is run.

Check that Logging service contractor is only using only zone 0 equipment and maintain the certification of same .

Be aware of that only GR; BHC and Induction Log are available for Pump Down Systems 2) (PDS) when using 3 1/2" DP.

A Side Entry Sub (SES) should be placed in the drillstring  but is only recommended with 9 5/8" casing or larger. The system available for 7" casing , with the 1" ID of the accompanying SES will not permit the passage of any back off tools. The Western Atlas 3 1/2" IF SES has an ID of 1.81" through which back off tools can pass .

When the Side Entry Sub on the bottom of the drillstring reaches the casing shoe it guides the multi conductor cable from the inside of the drillstring into the drillstring/ casing annulus.

Note that the  SES should not be run past  a point of  more than 30 inclination and not placed in a position where it will squash the cables against the low side of the hole.

General outline of procedures

The TLC/PCL system is a technique which can be used in highly deviated holes or holes with deteriorating conditions, where it is not possible to log on conventional wireline. The logging tools are run on drillpipe and the wireline cable is attached with a wet-connector on top of the tools. The cable is run through a Side Entry Sub (SES) to allow continuos logging and circulation.

Preparations prior to logging

-   Prior to and during the job, safety meetings should be held with each crew to highlight the operational steps

-   All drillpipe and the jar should be drifted (size to be checked with the contractor)

-   Two sets of wet connectors are to be supplied by the logging contractor.

-   Install the jar at approximately 200m above the wet connector. See that the jar stroke is completely extended ( if the jar is fired, run in hole and function test tools)

-   Make up any additional stands of drillpipe required to reach the bottom the logging interval.

-   Install intercom/ communication head sets and tension compression monitor near driller.

-   Have the logging unit positioned such that direct eye contact with drill floor is possible.

-   Cable cutter s on drill floor

Running tools into bottom of logging interval

1. Make up logging tools in rotary table .Test function of wet connector and logging tools ( check wet connection vertically in the rotary table, not horizontally on the floor). Before fully torquing up the IF connection of the latch assembly, put on the one single of drillpipe above to prevent sideways movement.

2. RIH 200m drillpipe.

3. Install jar.

4. RIH string slowly till tools are approximately 20-30m from top of  logging interval.

Note: CONTRACTOR PERSONNEL SHOULD BE ON DRILLFLOOR CONTINUOUSLY FROM THIS TIME ON.

5. Insert female part of wet connector in the Side  Entry Sub. RIH wireline cable a few hundred metres until it can run on its own weight.

6. RIH the Side Entry Sub on 1 joint of drillpipe (below BOP's) ,make up Right Hand Kelly Cock (RHKC) and circulation head (use DP-screen). the packoff seal of the side entry sub more effective when wet.

7. RIH wireline cable to approximately 50m above wet connector . Use snugger sheave (pull over sheave ) to pull cable back from drillpipe. Record cable tension.

8. Circulate for 10-15 minutes.

9. RIH wireline cable to wet connector  and latch on .(Depending on the depth, angle, etc. pump down while latching, contractor to advise )

10.If positive indication of latch :

- indication from line check (communication with tool)

- test logging tools

- make sure  pumps are off again before coming up

If not latched, pull out approximately 50m and try again . Circulate and try to find right pumping pressure and cable speed (contractor to advise).

11.POOH Side Entry Sub(SES)above table . Pull on cable to recorded cable weight . Slack off one (1) m  and put on clamp.

12.RIH tools to bottom of logging interval .Record weight of string up and down.

-       While running in , log down (contractor to advice on running speed).

-       Communication between driller and winch man is vital.

-       Watch for cable damage by slips and tongs

-       Contractor to advice on maximum compression allowed.

Logging

During calibration in open hole keep string moving to avoid  differential sticking.

Start logging up . After every stand set slips (minimise downward movement because caliper/ pad is open). Winchman to give slack after slips are set . Again: communication between winchman and driller is vital.

With the side entry sub back on surface, disconnect clamp and POOH with cable until  approximately  50m  below entry sub . Ensure the RHKC is installed on top (swabbing ).

Rig down sheaves and POOH logging tools

Hole problems

In case of stuck pipe: try to work string free, circulate . Use the jar only as a last resort .If unsuccessful, pull cable to side entry sub .

In case of well flow: retrieve cable if possible, otherwise cut cable above rotary and close BOP.

9.2 Recovery of Logging Cables under Pressure

General

Recovering unweighted logging cable by pulling through the lubricator while under well pressure is generally acceptable .

Adding sinker bars or weight above the weak point will hamper normal operations (not recommended).

Procedures

The operation carries out a higher than normal risk and requires specific procedures and extra precautions. The following points must be emphasised when recovering  the cables under pressure:

1. A safety meeting must be held with all staff involved to discuss the produce to be followed .

2. All personnel not essential to the operation are to be cleared from the wellhead rig floor area.

3. Ensure that proper means of communication between the operator at the lubricator and the winchman are available and in use .

4. Line up and test kill equipment before attempting to recover the cable . Also check grease injection equipment before commencing .

5. Lower top logging sheave as much as is practical to reduce free length of cable above the lubricator.

6. Do not use lubricator BOP rams to apply friction to the cable, apply sufficient grease injection pessure on the flow tube injection head to counteract/ control well pressure and reduce cable speed.

For more detailed information reference is made to the Integrated Service Contract manuals which will be available.

10. Stuck Tools

1. Keep the wire-line tension under constant review and in particular ensure that normal tension is known within 0.5 kN (100 lbs) at logging depth.

2. At the first sign of a sticking tool, alert the winch operator/engineer. Precise procedure to be followed subsequently depends upon a rapid assessment of the most probable sticking  mechanism. The four most probable causes of tool sticking are:

a)      Key-seated cable. This is caused by severe dog-legs, or as a result of the cable wearing a slot in the formation during a long logging operation.

b)     Key-seated tool head. This can happen in the vicinity of dog-legs, or in oval or key-hole shaped holes.

c)      Bridged hole. Often a result of shale collapse.

d)     Differential Sticking. This may occur when logging porous, permeable intervals in depleted reservoir zones, or intervals at much lower pressure than the mud column.

The procedure to be followed in the first three above cases (a, b AND c) is:

1. When an overpull of 2.2 kN (500 lbs) is reached, stop the winch, lower the cable until tension is 2.2 kN (500 lbs) below normal.

2. If the stuck tool has powered arms, close the sonde arms.

3. Reduce the tension to 4.4 kN (1000 lbs) below normal.

4. Observe whether the tool is still moving (in this case down).

5. If the tool is still moving, attempt to work the tool above the obstruction. While the tool will still move down the hole, do not apply an overpull more than 2.2 kN (500 lbs).

6. If the tool is NOT moving down, release tension further, to 6.7 kN (1500 lbs) or 8.9 kN (2000 lbs) below normal. Do NOT allow slack cable at the surface. Wait 5 minutes.

Note:    Do not exceed this limit without the approval of Base.

This procedure ensures that excessive pull is not applied in the initial stages, as this can jam the head, pads or cable into a key seat which can only be released by fishing. If the hole is bridged over, it is much better to be able to keep the tool moving below the bridge and attempt to work it through the obstruction than to lock it irrevocably into place with the first sharp pull.

When logging with a pad tool in porous and permeable sections of depleted reservoirs, differential sticking can be a problem. In this case, adherence to the above procedure may lead to unnecessary problems. If differential sticking is probable, follow the alternative procedure:

1. At the first sign of sticking, continue to increase pull to normal logging tension plus two thirds of nominal weak point strength.

Note:    Do not exceed this limit without the approval of the Base.

2. At 8.9 kN (2000 lbs) overpull, start to close the sonde arms.

3. If the tool comes free, re-open arms and continue logging.

4. If the tool does not pull free, reduce tension and work the cable up and down as in the first procedure.

If the tool is stuck, continue attempts to free it until the decision is made to cut the cable and strip over to the fish. The weak point must NEVER be broken when a tool is stuck in open hole EXCEPT when:

-       the cable has been stripped over and the head of the tool is securely engaged in the overshot, or

-       a decision has been made at Base either to abandon the tool, or to pull off and fish without overstripping.

Investigate the probable sticking mechanism by applying a stretch test, i.e. measuring the cable extension generated by 0.9 kN (200 lbs) increments of pull up to 8.9 kN (2000 lbs) above normal logging tension. Remember that, in deviated holes, friction at the dog-leg may give a false impression of key-seated cable.

Note: The incorporation of a down-hole tool head tension indicator in the tool string is being introduced on certain advanced telemetry tools. This device should improve the knowledge of down-hole conditions immeasurably, and may assist in avoidance of stuck tools, as well as   aiding in safe descent into highly deviated wells.

The implementation of the wire line logging programme at the well site is carried out by specialist contractors under the supervision of the Drilling Supervisor, although these responsibilities can be delegated to the Rig Drilling Engineer or the Well Site Geologist. The responsibilities of the well site personnel are identified below.

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The evaluation requirements for drilling operations are identified by the Reservoir and Petroleum Engineering Department and are incorporated in the drilling programme for each well, or as a separate test programme.

The implementation of the evaluation programme at the well site is generally carried out by the Logging Engineer under the supervision of the Drilling Supervisor. The responsibilities of the well site personnel are identified below.

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This article presents Formation Strength Tests Equipment and Procedure.

Equipment Requirements

A formation strength test requires:

• a Cement Pump with mud tank calibrated in ¼ bbl
• calibrated gauges covering anticipated pressure range mounted on a dedicated manifold
• a chart recorder
• a recording form.

Test Pressure Limitations

The test pressure shall be limited to a maximum pressure that does not exceed the lowest:

• leak-off pressure.
• limited pressure advised in the Drilling Programme (Limit Test) of the casing burst pressure
• wellhead test pressure
• BOP test pressure.

Procedure

The ‘hesitation’ method shall be used for all FST’s.  The following procedure should be adhered to:

1. DRILL OUT of the casing shoe to a minimum of 10ft of new formation below the shoe, unless advised differently in the Well Programme.

2. CIRCULATE and CONDITION the new mud until densities in and out are the same (no foam).

Note: At least one full circulation shall be made. The mud density out shall be checked using a pressure mud balance. All leak-off  tests shall be carried out with the mud gradient necessary to  over balance the anticipated reservoir pressures at the shoe by  200 psi.

3. PULL the bit back into the casing shoe.

4. ENSURE that the hole is filled up then CLOSE the BOP around the drillpipe.

5. PUMP mud slowly using the cement unit until the pressure builds up.

Note: Rig pumps shall not be used.

6. PUMP fixed volumes in pre-determined steps by using the calibrated displacement tank.

7. RECORD the pressure as soon as pumping ends and the gauge needle stabilises. WAIT two minutes then RECORD the static pressure.

8. REPEAT Steps 6 and 7 plotting versus cumulative volume pumped until the maximum pressure determined in accordance with company policies has been achieved or until formation breakdown occurs.

Note: Experience proves that graph should be plotted as the test is ongoing for optimum results. Formation breakdown is indicated when the final pump pressure deviates from the final     static pressure after shut in time. This point should coincide with the point where the pressure-volume plot departs from the normal straight line relationship.

9. MAINTAIN the well closed in for five minutes to verify that a constant pressure has indeed been obtained.

10. BLEED OFF pressure into the calibrated tank and CALCULATE and RECORD the volume of mud lost to the formation.

Note: If leak-off occurs before the minimum limit specified in the Drilling Programme is reached the Drilling Engineer shall be notified immediately to determine if remedial action or changes to the Drilling Programme are required.  The leak-off test results shall be reported in the morning reports.

Limit or leak-off tests in development wells may be omitted if no hydrocarbon bearing and/or overpressured formations are to be penetrated. Information obtained from leak-off tests in straight holes is not applicable to deviated holes in the same field (and vice versa). Only measurements in the deviated hole themselves should be used.

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In petroleum exploration, the geological model is developed and then proved, disproved, or modified by drilling. The subsequent commercial decisions are based on the existence and mobility of hydrocarbons within the pores of the reservoir rock under downhole conditions.

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Formation strength tests (FST’s - sometimes referred to as “leak-off tests” (L.O.T) or “limit tests” or “formation intake tests” (F.I.T)) measure the formation strength below the casing. FST’s, shall be done below all casing shoes (or outside milled casing windows for side-tracks) in exploration and appraisal wells.

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This article describes the responnsibilities for planing and safety, logging, Pipe conveyed logging(PCL), coring, mud logging, FST and Cement evaluation logging.

Planning and Safety

The Drilling Supervisor shall ensure:

• all personnel are familiar with the mandatory requirements for explosive and radioactive materials, (explosive magazines and radioactive stores shall be set aside in a designated, marked area away from the camp and rig traffic)
• the senior representative of the Logging Contractor and his crew are familiar with both Company and Contractor’s safety procedures, (the Drilling Contractor shall ensure that all personnel are aware of the dangers of radioactivity and explosives)
• all persons not directly involved in the tasks are kept well away from sheaves, cable and the winch drum when tools are being run and logging tools at surface
• loads are not moved across the cable when logging operations are in progress
• the hole is covered at all times unless a tool is being run in the hole. A slotted hole cover shall be installed whilst running logs.

Logging

Responsibilities for open hole evaluation tasks are given in the following table:

PCL Logging

The general responsibilities for PCL logging are given in the following table:

Coring Operations

The general responsibilities for coring operations are given in the following table:

Mud Logging

The general responsibilities for mud logging are given in the following table:

Formation Strength Test

Formation strength tests are directly supervised by the Drilling Supervisor.  The main responsibilities are given in the following table

Cement Evaluation Logging

The general responsibilities for cement evaluation logging are given in the following table:

This article presents the following Formation Strength Tests Calculations:

- Formation Intake Gradient (FIG)

- Effective Mud Gradient (EMG)

- Maximum Allowable Annular Surface Pressure (MAASP)

Formation Intake Gradient (FIG)

FIG (psi/ft) = LOP + (CSD x MG)

                      (CSD - RKB)

Effective Mud Gradient (EMG)

EMG (psi/ft) = LOP + (CSD x MG)

                            CSD

Maximum Allowable Annular Surface Pressure (MAASP)

MAASP (psi) = LOP - (CSD x MG)   (@ initial condition)

Where:

• CSD = Shoe Depth last set casing (ft TVD - RKB)
• MG = Mud Gradient (psi/ft)
• RKB = Rotary Kelly Bushings Elevation above ground level (ft)
• FBP = Formation Breakdown Pressure (psi)
• LOP = Leak - Off Pressure = Surface pressure recorded during the test (psi)

Evaluation work for an exploration well will be carried out from the Central Offices, so it is essential that the staff are kept up-to-date about what is happening in the field, and receive the data that they require, in the format they require.

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The evaluation requirements for a particular well depend upon the type of well being drilled eg., development, appraisal or exploration.  The detailed requirements for each well shall be indicated in the Well Proposal.

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A fully equipped computerised mud logging unit shall be available for recording and monitoring well generated data, for all exploration wells. There is no mandatory requirement for a full Mud Logging service for development wells which are not designated HTHP wells.

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This article describes the main geological services: Cutting sampling and description requirements.

Cuttings Sampling

Across reservoir: every 5 ft, and non-reservoir every 20 ft.

Cutting samples shall be taken from the full width of the shakers so as to be representative of the interval drilled. When drilling at high ROP the drilling contractor shall assign a roughneck as a sample catcher.

Cuttings Description

Lithological analysis of the cuttings shall be performed on the washed samples with the aid of a reflected light microscope. Fluoroscopic analysis shall be carried out on all samples. Any samples indicating fluorescence shall be treated with solvents to detect hydrocarbons and establish the nature of the cut.

Cuttings Handling

Washed samples shall be dried and packed in envelopes marked with the date, well number and depth. Wet unwashed samples shall be put into sample bags lined with a plastic bag at the time of collection at the shakers. Samples for geochemical analysis if required shall be packed in tins topped up with potable water. Bactericide shall be added before sealing the tin.

Depth Correction

Cutting lag time shall be known at all times. A carbide lag time test shall be performed every 12 hours or every 500 ft whilst drilling (especially in washed out N.Umer interval). The Driller and Drilling Supervisor shall be informed before performing a lag test.

All the parameters specified in the contract scope of services shall be recorded against time and depth and continuously monitored. The following table lists the recording frequency and standard units to be used for all mud logging parameters.

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Accurate cuttings descriptions are essential for the following 3 reasons:

• To pick out individual formation sequences as they are drilled, to establish stratigraphic position at all times, and hence to determine casing and coring points.
• To ensure that the well approaches the correct TD.
• To enable construction of a Well Completion Log, with all lithologies accurately described. This log allows detailed correlation to be made with neighbouring wells for development studies.

1       Sample Collection And Preparation

All mudlogging instruments should be checked and calibrated prior to spudding the well. It is particular important to check Total Gas, Chromatograph and H2S detectors.

Sample descriptions are required every 5 m in the reservoir.

2       Collection of Cuttings Samples

The overall objective is to obtain representative, clean samples, with an accurate assurance of the depths from which they are drilled. In order to achieve this it is essential to have an organised method planned for the sampling programme. The following are guidelines in this respect:

1) Samples should contain material collected from all shale shaker levels, and from the desilter/mud        cleaner. Use of sieves with suitably sized mesh for collection will facilitate rinsing of the samples. After rinsing, samples for immediate examination should be placed in sample trays,

2) Samples must be identified by well number and sample interval. It is essential that the marker pens used for labelling are insoluble to all types of drilling fluid. The sample depths must be corrected for bottoms up lag time, which should be theoretically checked by running carbide            checks.

3) One set of samples should be kept on the well site for reference until the completion of the next well. The remaining samples should be sent onshore at each section TD.

3       Cuttings Preparation

Samples shall be cleaned prior to description. Wash only enough samples to give a thin layer on the examination dish. Do not overwash, or grind the cuttings while washing - both may result in disintegration of the sample. Care must be taken not to rinse away soluble soft clays.

The cuttings shall be described in accordance with the Guide for Lithological Description of Sedimentary Rocks (Tapeworm 1966 version). The apparent subjectivity of cuttings description can be reduced by working through the different properties in a methodical manner, with consistent reference to the "tapeworm".

Cuttings descriptions are recorded by the mud loggers on a work sheet with provision for lithological descriptions, percentages of lithology for various intervals, penetration rates, gas levels, etc..

Mud and data logging comprise two distinct but complementary operations which may be combined, or alternatively mud logging may be carried out on its own.

1       General Requirements

Mud logging includes the following:

• Continuous logging of total gas and the chromatographic analysis of hydrocarbons.
• Detailed cuttings analysis including the description of lithology and hydrocarbon evaluation as specified.
• Taking of geological samples at the depths and in the manner required by the Company.
• Measurement and recording of bulk density.
• Correlation of cuttings lithology, gas analysis and hydrocarbon evaluation to reference material provided by the Company.
• Provision of daily reports as required.
• General assistance to Company personnel.
• Provision of personnel for core-catching operations and for detailed geological description of cores.
• Collection and description of sidewall samples.
• Collection and analysis of fluids from well tests as required.
• Monitoring and chart recording of basic drilling parameters.

Data logging includes the following:

• Monitoring and analysis of drilling operations and the recording of all data on tape or disc.
• Preparation of computer-processed printouts and plots of the recorded raw data and derived calculated data using standard software programmes.
• Preparation of the up-to-date pressure evaluation log incorporating the raw data plots of drill rate, corrected d-exponent, ditch gas values, shale density, etc.
• Preparation of up-to-date temperature data log using mud temperature parameters.
• Preparation of up-to-date pressure analysis log based on the above parameters giving the  estimated pore pressures, equivalent circulating density, overburden gradient, and estimated fracture gradient.
• Carry out formation pressure wire line log analyses as required to assist the company in evaluating the current downhole conditions relating to estimated formation pressure, formation gradient and casing shoe selection points.
• Provide a daily report on current drilling conditions as requested by Company Drilling Supervisor(s) or Well Site Drilling Engineer. The parameters reported include d-exponent, mud hydraulics, fracture gradient and estimated pore pressure and are derived from the basic software programmes or engineer determined values. Additional bit and cost calculations may be requested.
• Provide a weekly report detailing the drilling operation and any conditions of interest relating to abnormal formation pressure evaluation.

The full mud/data logging system is used for exploration wells, while for appraisal wells the data logging system may not be required if sufficient data regarding the area is already available. The plan for either requirement is detailed in the drilling programme for each well.

The services of the contractor shall be provided 24 hours per day in 12 hour shifts.

2       Equipment

It is the responsibility of the contractor to provide on board the rig the mud/data logging unit (as necessary) together with associated sensors in order to provide geological surveillance and on-line data recording and processing.

This equipment shall include:

1) Gas monitoring system including degasser, total gas detected, gas chromatograph with recorder, and hydrogen sulphide (H2S) monitor.

2) Mud monitoring system to automatically and continuously measure and display:

• Mud weight in and out.
• Temperature in and out.
• Mud flow in and out.
• Mud resistivity in and out.
• Pit volume totaliser (PVT) microprocessor system capable of monitoring all pits in any combination and to include audio visual high/low alarms for volume level or rate of change.
• Multi channel recorder.

3) Drilling monitoring system to automatically measure and display:

• Weight on bit.
• Hookload.
• Rotary torque and speed.
• Stand pipe pressure.
• Casing pressure.
• Drilling rate (in metres/feet per hour) independent of the rig depth recorder system.
• Pump stroke counter.

4) Geological and auxiliary equipment to allow a normal formation evaluation service to be performed and including microscope, fluoroscope, drying ovens, chemicals etc.

5) Computer hardware and software used in the logging process, with interfaces to the monitoring systems and provides automatic data collection transfer, processing and recording.

3       Logs and Reports

The following logs and reports shall be prepared by the contractor:

1. Logs

A formation evaluation log prepared to Company requirements of 1:500 in meters. Other scales may be specified by prior notice. The logs shall include:

• Lithological percentage, description and interpretation.
• Visual porosity.
• Drill rate.
• Ditch gas.
• Chromatographic data.
• Cuttings gas.
• Oil fluorescence and descriptions.
• Core intervals and descriptions.
• Mud data.
• Bit data and other relevant engineering data.
• Deviation surveys.
• Other logs which may be requested are:
• Drilling data pressure log.
• Pressure analysis log.
• Temperature data log.
• Wireline pressure log.
• All these logs are up-dated regularly on sepia and paper field prints are available at all times.

2. Tapes, discs and printouts

Full sets of magnetic tapes or discs together with the required number of hard copy printouts and plots are taken.

3. Final well report

After the completion of the well a final well report shall be available from the contractor. This report is prepared at the well site and compiled at the contractors office unless otherwise specified.  This report briefly summarises the geology of the well and highlights any points of geological or engineering significance.

1. Size of the production test crew

A minimum of rig personnel should be on board during well-testing operations. Well test personnel will complement the rig personnel some time prior to the actual test operations and although it is desirable to keep the number of the latter group to a minimum, care should be taken that no person in either group will be committed to work excess hours. Mistakes resulting in damage and/or injury have sometimes been caused by fatigue of personnel. One of the measures to be taken to prevent accidents, therefore, is to avoid excessively long working hours. Operating companies should make sure that their supervisory staff in charge of operations, keep track of hours worked by all personnel, including themselves and contractors.

1.For a short duration production test (one zone, 24 hours flow period), two production test supervisors and a wireline operator are considered sufficient. When more zones have to be tested and the duration of the flowing periods may be several days or weeks it is advisable to have on board, one senior production tester, 2 production testers, 2 assistant testers, 1 wireline operator and a helper.

2.For operations involving the use of a subsurface test tree, two additional operators are required. These operators will be on the drill floor on a 12 hours on/off basis during the time that the SSTT is in the hole.

3.For downhole pressure and temperature measurement with surface read out, specialists are required. For long duration testing, it is advisable to have 2 specialists on site. When the production testing contractor also provides the reel unit with the electric cable, the regular wireline operator should be capable of running these tools alternatively, for BHP/BHT with surface read out, operations can be conducted by the logging contractor.

The fees for contract personnel are high, and operating companies must therefore insist on quality and should check the experience and curriculum vitae of service personnel. Some service companies may recommend that their chief operator carries out the actual wireline operations which would result in decreased charges. However, cost savings in this direction are misplaced. Experience has shown that the two functions are difficult to combine.

2 Company supervision

Throughout the production test there should be an experienced production operations engineer and a petroleum engineer on site who are familiar with both the practical production testing techniques as well as the theory.

3 Responsibilities/duties during testing operations

3.1 The Contractor Drilling Supervisor (CDS)

The Contractor Drilling Supervisor or Contractor Drilling Superintendent is responsible for the rig safety at all times and is the central point of authority. He has overall responsibility for the well and rig safety during all operations including production test and the suspension/abandonment operations.

3.2 The Company Drilling Supervisor

The Drilling Supervisor co-ordinates and monitors the operations and should keep himself fully informed of the progress of the test at all times. He must be advised by the Petroleum Engineer (PE) before the well is perforated and by the Production Operations Engineer before the well is opened up, and at any time that a potentially hazardous situation may occur. He in turn will inform the PE of any activity or occurrence which could effect production operations.

 3.3 The Production Operations Engineer (POE)

The Production Operations Engineer supervises the operations of running the tubing, wireline work, opening up, beaning up, blowing off and testing of the well. He is responsible for the safety precautions on the surface production facilities from wellhead to flare. He ensures that an accurate record is kept of all information requested in the testing programme.

3.4 The Petroleum Engineer (PE)

The Petroleum Engineer is responsible for the test meeting the requirements of the test programme. He keeps a tally of all equipment run in the hole. He is responsible for logging, packer setting, perforating, stimulating P.V.T. sampling and in general for all the information generated by the test.

3.5 The Production Test Contractor

The Production Test Contractor has the responsibility to check all his equipment before the test and perform the necessary safety checks. During the test, the production test operators operate the choke-manifold, heater, separator, burners and transfer pump while taking the necessary measurements. The subsurface operators have to be on the drill floor near the controls of the SSTT on a 12 hours on/off basis. The production test operators should only follow the instructions of the Company Production Operations Engineer.

3.6 The Barge Engineer

The Barge Engineer remains in constant communication with the person in charge of the rig. He is responsible for the supply of air to the burners and for the supply of water to the water sprinkling system. When the cooling system is not sufficient he will rig up firewater hoses and flush the equipment which gets too hot. When steam is used as a heat exchange medium, he ensures adequate and continuous supply.

3.7 The Driller

The Driller and two floormen will be available on the derrick floor. The Contractor Drilling Supervisor may give the Driller specific instructions in connection with well/wellhead safety.

 3.8 The Radio Operator

Before the radio transmitters are switched off for perforating operations, the Radio Operator must inform the standby boat and the base. He should remain in the radio room. Only one person should be empowered to order him to switch the equipment on and off; this is usually the Company Drilling Supervisor.

3.9 Miscellaneous

The assistant driller, derrick man or one floorman must be in the pump room, and have killing fluid and equipment ready for killing/circulating of the well.

The kill-pump operator must be available at all times, to pressure test and kill the well, when required.

4 Communication and reporting

The Production Test Contractor who reports directly to the Production Operations Engineer. Only the POE gives instructions to the Production Test Contractor(s).

The logging contractor, the mud engineer and the mud logging engineer who report directly to the Petroleum Engineer. Only the PE gives instructions to these contractors.

The POE and the PE make a joint progress report at the end of the day which is handed to the SDS unless otherwise agreed. For instance during running in the tubing it will be impractical to give all instructions via the SDS.

Although during the course of a production test it may seem impractical and time consuming to follow the reporting channels, it is of importance that everybody strictly adheres to it.

It is therefore advisable to have a meeting (normally the "Safety meeting") with everybody concerned (including radio operator, barge master, chief engineer, chief electrician etc.) where this subject is explained and discussed, before the test.

Although there is a strong tendency nowadays to contract out all services required on a well test, it is strongly recommended that overall control still be retained by having Drilling Supervisors and Petroleum Engineers.

*1 5000 psi well testing programme
*1.1 Test objectives
1.To test the transition zone to determine the maximum water saturation at which oil will continue to be produced.
2.To determine the extent of the reservoir and the deliverability of the hydrocarbons.
3.To obtain representative samples of reservoir fluids for compositional, PVT analysis.
*1.2 Basic data (determined from final log analysis)
Tests 2 and 3 are subject to participant approval. For this reason production test time schedules (Section *3.16) and suspension diagram (Section *3.17) have been submitted for both the 2 test and 3 test cases.
Test 1Test 2Test 3
1.Test interval (m.ahd)2918-2930 m2834-2846 m2821-2823.5 m
2.Perforation intervals2923.5-2925.5 m and 2926.5-2929 mas aboveas above
3.Type of perforator111/16 Enerjets21/8" Enerjets21/8 " Enerjets
4.Shot density13 shots/m13 shots/m13 shots/m
5.Estimated formation pressure29080 KPa @ 2912.5 m28625 KPa @ 2836 m28545 KPa and 2820 m
6.Equivalent mud density1.02 S.G.1.03 S.G.1.03 S.G.
7.Formation fluid expectedoil/water /gasoil/gasoil/gas
8.Reference logGR/DLL/MSFL30/6/90
9.Type and density of completion fluidKCl brine1.06 S.G.
Depths quoted are referenced to the above Ref. Log, in metres along hole below rotary table (m.ahbrt).
1.3 Introduction
1.This production test will be carried out under the supervision of Woodside Offshore Petroleum Pty. Ltd., Well Engineering, using the semi-submersible rig "Margie".
2.The test programme has been designed with reference to Woodside's "Production Test Guidelines", document No. A1170SD002, Revision dated August 1988.
3.The following is the test outline:
-Production test 1:
-Perforate 2923.5-2925.5 m.ahd in the transition zone.
-Flow at maximum practical rate.
-If water is produced, run PLT to determine influx point and flowing and static pressures. No further testing of the transition zone is required.
-If no water is produced, additionally to perforate 2926.5-2929 m.ahd.
-Flow commingled at maximum practical rate and run PLT to determine the contribution of the second perforated interval, the origin of the water, and flowing and static pressures.
-Isolate the perforated intervals with an XN plug.
-Production test 2
-Standard flow and build up test over the interval specified in Section *1.2.
-Isolate the perforations with a MPBT through tubing bridge plug.
-Production test 3: Flow for sampling purposes over the interval specified in Section *1.2.
4.The test string will be 31/2" OD, 10.3 lb/ft, Hydril 'CS' tubing.
-One 7" Baker Model FB-1 production packer, size 85-40, with mill out extension and 1.875" XN Landing Nipple will be set on wireline to test and isolate the bottom zone.
-One 7" Baker Model FB-1 production packer, size 85-40, with seal bore extension will be set on wireline to test the upper zone and locate the test string seal assembly
5.Perforations will be made using Schlumberger 111/16" OD Enerjets, 13 shots per metre for the first test, and 21/8" Enerjets, 13 shots per metre for the remaining tests.
6.Maximum flow rates will depend on reservoir productivity, nature of the fluids in the formation, the capacity of surface facilities and whether wireline tools are used during flow periods.
7.All hydrocarbons produced and not retained as samples will be flared off at the wellsite.
8.Burner operation shall be monitored at all times to ensure efficient operations. The number of burner heads may have to be limited during low flow rate periods and during killing operations. Flow should be diverted to the surge tank or the well shut-in if burner operations is questionable. Accidental oil spills must be reported as per The Petroleum (Submerged Land) Act.
9.The well will be suspended at the completion of the production test.
1.Four Halliburton HMR quartz gauges with large memory capacity will be run in a Halliburton Gauge Bundle Carrier.
2.These four gauges should ensure sufficient data is acquired.
3.Equipment Test Pressure upstream of the choke manifold shall be 34.5 MPa (5,000 psi) unless otherwise stated.
4.A Schlumberger CRG Surface Readout Gauge will be used for Production Test 2.
*1.4 Preparation phase
Note:
Detailed running and testing procedures are given respectively in Section 7 and Appendix B of the "Production Test Guidelines" (PTG).
1.Run in hole, to 95/8" wear bushing, with fluted hanger on 5" OD drill pipe with the pipe painted in the vicinity of the No. 2 Pipe Ram to verify the distance from the ram to the wear bushing. Verify that the No. 2 Rams will seal around the 5" OD drill pipe. Note the distance from the Rotary Table to the 95/8" Wear Bushing, for space out. Refer to the PTG as above, paragraph 7.1.1 for details.
2.Pull out of hole.
3.Make up the Sub-sea Test Tree (Sub Assembly No. 9) in a stand, and stand back in derrick.
4.Make the up the Sub-sea Lubricator Valve (Sub Assembly 10) in a stand, and stand back in derrick.
5.Make up the Flow Control Head (Sub Assembly No. 11) on to a joint of 5" OD Vam casing, set back on cat-walk and perform a body pressure test.
At this stage avoid any internal contact of Sub Assemblies with mud.
6.Make up 5" OD VAM casing that will be used to space out between sub-assemblies 9 and 10 into stands and stand back in derrick.
7.Physically check all Sub-Assemblies previously made up at shore base and lay them out, ready to run in the hole.
8.Rig up Schlumberger: Run 7" casing Gauge Ring/Junk Catcher to +/- 10 metres above the plug back depth.
*1.5 Test phase
Refer to Section 8 of "PTG" for radio silence requirements.
1.Run in hole with 7" Baker FB-1 Packer with mill out extension and 1.875" XN Nipple (Sub Assembly No. 1B) on Schlumberger wireline and set the lower packer (to test the Transition zone) at 2885 metres AHD.
The bottom of the tail pipe must be set at least 25 metres from the anticipated top perforation to allow access for the PLT tool string.
a)Run in hole with 7" Baker FB-1 Packer with seal bore extension (Sub-Assembly No. 1A) on Schlumberger wireline and set the upper packer at 2800 metres AHD.
2.Run the production test string with reference to Section 7 of "PTG". Note that this programme supersedes the PTG with respect to the actual string to be run. See schematic Completion Diagram in Appendix 3 of this programme.
3.Assemble and run production test string Sub Assemblies Nos. 2, 3H, and 6H.
1.Ensure that 4 Halliburton HMR gauges with high temperature, long duration (lithium) batteries are installed in the Halliburton Bundle Gauge Carrier.
2.Ensure that the Omni valve is run in position No. 7.5, Well Test position, (see Section *1.11 for Omni valve setting positions).
4.Run the required 31/2" OD, CS Hydril, tubing until the Wireline Entry Guide of Sub Assembly No. 2 is approximately 1 to 2 metres above the upper 7" Baker FB-1 packer.
5.Stab carefully into the packer while circulating slowly. As soon as a pump pressure increase is observed pull back 2 metres and note tubing measurements for space out. Circulate the tubing and annulus volumes with clean brine until returns are clear.
6.Close the No. 3 variable bore reams and cycle the Omni valve to position No. 9.5, blank position. Pressure up to the tubing of 34.5 MPa (5,000 psi) for 15 minutes to test the tubing. Bleed off the tubing pressure.
7.Cycle the Omni valve to position No. *5, circulate position.
8.Pull back, install Cross-over Assembly No. 7 and space out using 5" Vam casing pup joints.
Install Hang Off Coupling (Assembly No. 8)
Install Sub-sea Test Tree (Assembly No. 9) followed by 5" Vam casing
Install the Sub-sea Lubricator Valve (Sub Assembly No. 10) approximately 30 metres below the Flow Control Head swivel, followed by 5" OD Vam casing, to bring the bottom of the G-22 Locator Seal Assembly (Sub Assembly No. 2) +/- 2 metres above the upper 7" Baker FB-1 packer.
9.Hang off tubing on No. 2 Pipe Rams.
10.Connect chiksans to tubing. Cycle the Omni valve to position No. 15.5, blank position.
11.Pressure test string to 34.5 MPa (5,000 psi) for 15 minutes.
12.Cycle the Omni valve to position No. 6.5, well test position.
13.Pick up string from and open No. 2 Pipe Rams.
14.Install the Flow Control Head (FCH) (Sub Assembly No. 11) with 15 metres slings. Connect Flow and Kill lines. Pressure test the kill and flow lines and FCH against closed Sub-sea Lubricator Valve to 34.5 MPa (5,000 psi).
15.Stab carefully into the packer while circulating slowly. As soon as a pump pressure increase is observed pull back 2 metres.
16.Displace the tubing volume to Diesel, leaving 0.5 m3 (3 BBL) of Brine in the bottom of the tubing, using the cementing pump and pumping through the FCH's kill line with returns to pits. Note tubing head pressure.
17.Lower the test string and stab into the packer carefully. Land the test string to allow +/- 2 metres of tubing movement above the packer and hang off with the Fluted Hanger at the 95/8" Wear Bushing.
Note the Tubing Head Pressure and then bleed down slowly. Clear the kill line of all diesel and flush across the surface tree with brine.
18.Close the No. 2 Pipe Rams around the Slick Joint below the SSTT and with the tubing open, pressure test the annulus to 13.8 MPa (2,000 psi). Bleed the annulus pressure back to 1500 psi and monitor the pressure continuously during testing. Note that the Omni valve will cycle to position No. 7, well test position.
19.Rig up the Schlumberger Lubricator and BOP's. Function and pressure test same to 34.5 MPa (5,000 psi) against closed Master Valve.
20.Run in hole with CCL log, incorporating a 111/16" OD gauge, to Hold Up Depth to correlate perforation intervals, check on depth of string components and make a perforating "dummy run" to ensure the 111/16" OD enerjets will pass freely through the test string.
*1.6 Production Test 1 (2918-2930 m ahd)
Refer to Section 8 (Perforation safety) of the PTG before perforating.
1.Run in hole with 111/16" OD Schlumberger Enerjets guns, loaded with 13 shots per metre, at single phasing and magnetic positioning tool. Open well on small choke, bleed off Wellhead Pressure to zero and leave choke open.
2.Perforate interval 2923.5-2925.5 m (Ref. log Schlumberger GR/DLL/MSFL, 30.6.90).
3.Flow well on small choke to clean up perforations for 5 minutes.
4.Shut well in at Choke manifold. Wait 5 minutes to allow debris to settle then pull gun strip out of well and conform that all shots have fired.
5.Open the well in stages to the maximum allowable flow rate with the available surface production facilities. Flow for a minimum of 6 hours and until stable conditions are obtained over a one-hour period.
Formation fluid samples shall be taken as below:
-4 sets Schlumberger recombination samples,
-2 sets WOP Karratha recombination samples,
-2 ´ 20 litre gas bottles of produced water under pressure,
-10 ´ 4 litre flagons of produced water,
-4 ´ 25 litre cans of stock tank oil.
6.If water is produced, proceed with the PLT as in step 7. If water was not produced:
a)Rig up to reperforate with 111/16" Enerjets, single phased, 13 shots per metre, between 2926.5 and 2929 m.AHD. Pull the gun and check that all shots have fired.
b)Flow the well until stable bottom-hole conditions are judged to have been attained.
c)Shut in the well. Proceed with step 7.
7.Run in the well with PLT at the discretion of the Production Technologist in consultation with the Reservoir Engineer. The tool must be safely below the tail pipe during all flow periods. Take pressure readings at the HMR gauges and mid perforations.
8.Open the well at the flow rate at which water was produced and conduct the PLT survey.
9.Shut in the well before pulling the PLT tools into the tail pipe and pull the PLT out of the well. Note final THP.
10.Proceed to Section *1.7 (Production Test 2).
The actual flow rates and the duration of flow and shut in periods is subject to confirmation by the Production Technologist in consultation with the Reservoir Engineer.
*1.7 Production Test 2 (2834-2846 m.AHD)
Applies after the well has been shut in after Production Test 1.
Tests 2 and 3 are subject to participant approval. For this reason production test time schedules (Section *1.12.4) and suspension diagram (Section *1.12.6) have been submitted for both the 2 test and 3 test cases.
1.Set an XN plug in the XN nipple.
2.Run 21/8" tool on slickline to act as dummy for the 21/8" Enerjets.
3.Bleed off pressure from tubing string to atmospheric pressure so that a drawdown equivalent to the final THP from Production Test 1 tests the XN Plug from below.
Monitor volumes of evolved gas to ensure that test string remains full of liquid. Fill tubing with sea-water, if significant gas evolved.
4.Observe that the well is dead for 30 minutes.
5.Run in hole with 21/8" OD Schlumberger Enerjet guns, loaded with 13 shots per metre, at single phasing and magnetic positioning tool. Open well on 1/4" choke, bleed off wellhead pressure to zero before perforating and leave choke open. Perforate interval 2834-2846 metres AHD. Reference log Schlumberger GR/DLL/MSFL, 30.6.90. Monitor CCL for cable lift and close well, if lifting occurs.
6.Flow well on 1/4" choke (or as required to avoid cable lift) for 5 minutes to clean up perforations.
7.Shut in the well at the choke manifold.
8.Wait 15 minutes to allow debris to settle then pull gun strip out of the well and confirm that all shots have fired.
9.Open the well to clean up at the maximum allowable flow rate with the available surface production facilities.
10.Shut in the well.
11.Run Schlumberger CRG SRO gauges to below perforations.
12.Flow the well at highest possible flow rate until stable bottom-hole conditions are judged to be obtained. Maximum flow rate is limited by the cable lift of the CRG SRO gauges.
The length of this flow period shall be sufficient to condition the well for the build up phase and to achieve stabilised bottom-hole and surface conditions. Two pairs of separators oil, water and gas samples will be collected towards the end of the first few hours of flow as a contingency against the test being abandoned early.
Formation fluid samples shall be taken as below:
-4 sets Schlumberger recombination samples,
-2 sets WOP Karratha recombination samples,
-10 ´ 4 litre flagons of produced water,
-4 ´ 25 litre cans of stock tank oil.
13.Shut in the well at the wing valve and observe the build up for a period of 24 hours. Note final THP.
The actual flow rates and the duration of all flow and shut-in periods is subject to confirmation by the Production Technologist in consultation with the Reservoir Engineer.
14.Pull out of the hole with the CRG SRO gauges.
15.Run tandem bottle hole sampler.
16.Flow well at low rate for 30 minutes.
17.Shut in well and take bottom-hole samples.
18.Pull out of hole with bottom-hole samplers. Perform on site quality checks are required. A minimum of 2 valid bottom-hole samples is required.
*1.8 Production Test 3 (2821-2823.5 m.ahd)
Applies after the well has been shut in after production test 2 (Section *1.7).
Tests 2 and 3 are subject to participant approval.
For this reason production test time schedules (Section *1.12.5) and suspension diagram (Section *1.12.6) have been submitted for both the 2 test and 3 test cases.
1.Run in hole with a Schlumberger 21/8" MBPT Through Tubing Bridge Plug.
2.Set MBPT at 2832 m.ahd. Pull setting tool back into tubing.
3.Test the MBPT as follows:
Bleed off pressure from the tubing string so that:
Tubing pressure = final THP (production test 2) - 400 psi.
If final THP (production test 2) is less than 400 psi, bleed off to atmospheric pressure.
Bleed off in 100 psi stages, monitoring volumes of fluid returns from well.
Monitor volumes of evolved gas to ensure that test string remains full of liquid. Fill tubing with sea-water, if significant gas evolved.
4.If MBPT fails pressure test, tag MBPT with setting tool to see, if the MBPT has moved up hole. Pull out of hole with setting tool.
In the event that the MBPT fails the pressure test and has not moved up hole to such a depth that would cause interference with the planned perforations a dump bailer run will be required to attempt to provide isolation.
5.If MBPT passes pressure test pull out of hole with setting tool string.
6.Run in hole with 21/8" OD Schlumberger Enerjet guns, loaded with 13 shots per metre, at single phasing and magnetic positioning tool. Open well on 1/4" choke, bleed off wellhead pressure to the minimum allowable (test pressure from step 3) before perforating and leave choke open. Perforate interval 2821-2823.5 metres AHD. Reference log Schlumberger GR/DLL/MSFL, 30.6.90. Monitor CCL for cable lift and close well in, if lifting occurs.
7.Flow well on 1/4" choke (or as required to avoid cable lift) for 5 minutes to clean up perforations.
Flow rate will be limited by the amount of drawdown that can be applied to the MPBT.
8.Shut in the well at the choke manifold.
9.Wait 15 minutes to allow debris to settle then pull gun, strip out of the well and confirm that all shots have fired.
10.Flow the well at highest possible flow rate until stable bottom hole conditions are judged to be obtained.
The length of this flow period shall be sufficient to achieve stabilised bottom-hole and surface conditions.
Formation fluid samples shall be taken as below:
-4 sets Schlumberger recombination samples,
-2 sets Schlumberger recombination samples,
-10 ´ 4 litre flagons of produced water,
-4 ´ 25 litre cans of stock tank oil.
11.Run bottom samplers at the discretion of the Reservoir Engineer, if the surface samples show that the oil from the upper zone is significantly different from that seen in Wanaea 1 or 2.
On site quality control checks to be carried out on the samples as required. A minimum of 2 valid samples is required.
12.Shut in the well.
The actual flow rates and the duration of all flow and shut-in periods is subject to confirmation by the Production Technologist in consultation with the Reservoir Engineer.
*1.9 Well killing and isolation phase
1.Once the production test has been completed cycle the Omni valve to position No. 12.5, circulate position. Circulate in reverse to kill the well with completion brine at 1.06 S.G. Reverse circulate bottoms up through the open choke to the burners.
If the Omni valve fails, the well should be killed by the following preferred methods in order, depending on the mode of failure of the Omni tool:
1.Open the rams and pull the tubing stinger out of the packer to reverse circulate for the kill.
2.Run in the hole with a tubing perforator gun and perforate the 31/2" tubing immediately above the Omni valve.
3.Bullhead completion brine down the tubing to the top perforation. Note pressure limits imposed by the MPBT.
Any oil returning from the tubing will have to be burnt off.
Ensure that burners are operating properly at all times. Direct flow to the surge tank or shut well in if burner operation is questionable..
2.Cycle the Omni valve to position No. 2.5, well test position.
3.Open the No. 2 Pipe Rams and pick up on the test string so that the seal assembly is out of the packer. Hang off the Hang-Off Coupling (Assembly No. 8) on the No. 2 Pipe Rams.
4.Circulate normally through the choke line and choke manifold back to the mud pits until acceptable gas levels are reached.
5.Observe that the well is dead for 30 minutes. Pull test string out of the well and lay out the same.
*1.10 Well suspension/abandonment
*1.10.1 2 Test intervals
1.Pick up a 23/8" tubing stinger approximately 140 metres long on drill pipe and run in the hole. Run the 23/8" tubing stinger through the packer at 2800 m.ahd and tag the packer at 2885 m. ahd.
2.Rig up to cement and pump a volume sufficient to cover to 30 m.ahd above the top perforations. Displace the cement as a balanced plug and pull the tubing to well above the calculated cement top, close rams and reverse circulate out more than the cementing string volume. Squeeze away a maximum of 0.1 m3 (0.6 bbl). Pull back 1 stand. Circulate and work pipe.
3.Wait on cement, run in and tag the cement top. Pull up well above the cement circulating every stand, close the rams an test the plug to 6895 KPa (psi) for 15 minutes.
4.Pull out of the hole to ± 410 metres below the sea-bed and set a high viscosity brine pill to 310 metres below the sea-bed. Pull out to ±310 metres below the sea-bed and set a balanced cement plug of at least 60 metres length, with the cement top at ±250 metres below the sea-bed.
5.Wait on cement, run in and tag the cement plug. Pull and lay down remaining tubing.
6.Pull BOP and riser.
7.Install corrosion cap with oil and grease in the well-head area.
*1.10.2 3 Test intervals
1.Pick up a 23/8" tubing stinger, approximately 140 metres long on drill pipe and run in the hole. Run the 23/8" tubing stinger through the packer at 2800 m.ahd and gently tag the MBPT at 2832 m.ahd.
2.Rig up to cement and pump a cement volume sufficient to cover the perforated interval to 50 metres above the top packer (50 sacks of cement). Displace the cement as a balanced plug and pull the tubing to well above the calculated cement top, close rams and reverse out the tubing volume. Squeeze away a maximum of 0.1 m3 (0.6 bbl). Circulate and work pipe.
Maximum squeeze pressure limited to 400 psi due to the limitation of the MPBT.
3.Wait on cement, run in and tag the cement top. Pull up well above the cement circulating every stand, close the pipe rams and test the plug to 6895 KPa (1000 psi) for 15 minutes.
4.Pull out of the hole to ±410 metres below the sea-bed and set a high viscosity brine pill to 310 metres below the sea-bed. Pull out to ±310 metres below the sea-bed and set a balanced cement plug of at least 60 metres length, with the cement top at ±250 metres below the sea-bed.
5.Wait on cement, run in and tag the cement plug. Pull and lay down remaining tubing.
6.Pull BOP and riser.
7.Install corrosion cap with oil and grease in the wellhead area.
*1.11 Omni valve setting position chart
Operation and recording of the Omni valve positions shall be carried out under the supervision of the Halliburton Operator.
An Omni valve setting position chart shall be kept on the rig floor and updated at all times during the test.
A chart recorder shall be maintained on the annulus at all times during the test to verify the Omni valve position.
*1.11.1 Precautions for running the Omni valve
1.Do not run the Omni valve in the blank position with more than 2000 psi differential below the ball.
2.Do not run the Omni valve ball in the closed position, (blank or circulate) in conjunction with another closed ball tool or any otherclosed system.
3.Do consider casing pressure limitations at all times.
4.Always allow 1000 psi difference when running more than one annulus operated tool.
5.Pressure recorders must be used on the annulus and tubing string at all times while the Omni valve is in use.
6.Do not pressure test in the 101/2 position.
7.Do not run in the 11/2 or 141/2 position.
*1.12 Sampling and data acquisition
*1.12.1 Sampling (to be carried out by Production Test Contractor)
The following types of samples are to be taken as per the test programme:
1.separator gas - in 20L (Schlumberger) sample bottles,
2.separator liquid hydrocarbons - in 628 cc (Schlumberger) sample bottles
3.stock tank liquid - in 25L drums,
4.produced water - in 4L glass flagons and 600 cc (Schlumberger) sample bottles).
Samples bottles should be labelled and should include the following information:
1.well name and number,
2.test number (depending on number of zones to be tested),
3.test date,
4.interval tested, m.bdf,
5.sample type,
6.sample point (separator, flowline manifold, gauge, tank),
7.sample number,
8.date and time sample taken,
9.production rates oil and gas (and water).
After samples have been taken they should be packaged in their protective cases, whenever applicable, and labelled with their final destination.
*1.12.2 Data acquisition
Data required comprises:
1.Wellhead pressure (WHP) using dead weight tester and Vaetrix gauge
2.Wellhead temperature (WHT)
3.Separator pressure and temperature (vessel and gas line temperatures)
4.Liquid flowmeter factor
5.Production rates oil and/or water in m3/day, gas in 106 MMstm3/d.
6.Orifice plate size (inches)
7.Choke size (64/64")
8.Shrinkage factor
9.BS and W (%)
10.Oil gravity/temperature
11.Gas gravity/temperature
12.Continuous bottom-hole pressure and temperature (BHP and BHT).
13.H2S (ppm) and CO2 (% vol.)
14.Water (gravity/salinity/resistivity/temperature).
*1.12.3 Production test completion diagram
*1.12.4 Completion fluid details
The 95/8" and 7" casing volumes will be displaced to 1.06 S.G. KCl brine prior to running the test string.
The brine should be treated as follows:
•Add 1-2 kg/m3 caustic to give pH 9
•Add 0.5-1 kg/m3 coat 129 to give sulphite residual of 150-200 ppm
•Add nitrate to 200 ppm.
Filter brine through 28/10 micron filters. Take care to keep discharge line outlet emerged in the filtered brine, as this will use up the oxygen scavenger (sulphite). If pressed for time, filter only enough brine to fill two liner volumes and save this so it can be spotted across the test intervals. The rest of the brine can be filtered while running the tubing. The purpose of the filtration is to prevent particulate from entering the reservoir so it is critical that clean fluid be across the perforations.
•After filtration,
•Add 0.5 litres per m3 Surflo H-35
•Add 1.5 litres per m3 Surflo B54X (Refer to "Chemical Data Sheets" for Safety Precautions).
And ensure that this is thoroughly mixed in the brine before pumping downhole.
*1.12.5 Production test time schedule
*1.12.6 Suspension diagram
*2 10,000 well testing programme
*2.1 High pressure appraisal well, West Stadrill, Version, 26 February 1991, 211/14-4 RE
*2.2 Testing programme amendment No. 1, Date: 24 February 1991, Well: 211/14-4 RE
Test programme is to be modified at step 1 and step 2. An extract of programmes given below. Step 3 on are unchanged and given for information only.
1.Apply 2,000 psi to Annulus to open PCT. Monitor annulus pressure over 15 minutes to test pipe rams around SSTT slick joint. Cycle PCT to "lock open" position by pressuring up ad releasing pressure in the annulus.
2,000 psi required for first opening only. Thereafter opening pressure will be 1,500 psi.
2.When PCT is in locked open position and annuls pressure is zero, increase surface pressure to 5,000 psi through tubing to rat hole to provide 2,000 psi differential from below packer. (Observe annulus for pressure increase). From volumes pumped in test at 2.3.6, it can be determined whether PCT is open .
3.Bleed off applied tubing pressure, to give 500 psi static underbalance.
4.Rig up Atlas Wireline for running wireline guns.
*2.2.1 Phase 3 - Perforation and evaluation of lower Brent sandstone
Make drift run with dummy wireline guns. Make the dummy length as close to the actual as possible to give a realistic trials.
*2.3 Testing programme amendment No. 2, Date: 5 March 1991, Well: 211/14-4 RE
This is by way of follow up to our conversation. This afternoon regarding hang up of tools at wellhead.
1.Rig up and run LIB through subsurface equipment.
a)If the LIB passes subsurface equipment at previously encountered hang up depths (678 and 698 ft), then proceed to run dummy guns.
b)If the LIB does not pass, go to step 20.
2.Pressure up tubing to previous differential pressure. Open PCT, and pull string out of packer.
3.After string is out of packer, close pipe rams and cycle PCT to closed position. Open pipe rams.
4.Pull back landing string and SSTT.
5.Lay out SSTT. Look for obvious problems with equipment. However, do not dismantle SSTT.
6.Pick up back-up SSTT. Make up on string as per previous test string.
Before flowhead is on:
Test string to 7,500 psi against. PCT. Inflow test sub-sea test tree and lubricator valves. Cycle PCT to lock open position. Stab in to packer. Attach flowhead and land off.
7.Pressure test against retainer and lubricator valves against 9,000 psi.
8.Return to programme Section *2.2 step 1.
*2.4 Introduction
Appraisal well 211/14-F (spudded as 211/4-4) is designed to establish reserves and reservoir productivity of Middle Jurassic Brent and to recover water from the Triassic Nansen/Statfjord sands of the 211/13-2 prospect, east of the Penguin Horst.
Neither the discovery well 211/13-2 or the follow up 211/13-6 were tested, so the reservoir fluid and productivity are uncertain.
Estimated pressure at 11,520 ft tvss is 8,065 psia (Brent sands) and at 12,124 ft tvss 8,550 psia (Statfjord). Available data implies overpressures up to 3,000 psi.
The test will comprise testing the poor quality Rannock, followed by an additional perforation and test of the upper, higher quality, Etive.
*2.5 Test objectives
1.To collect representative hydrocarbon samples in order to determine reservoir fluid type, and collect representative water samples.
2.To assess reservoir productivity and parameters, kh and skin, for each zone tested.
3.To determine upside and test sand face integrity in the Brent group by a maximum rate flow test (unstimulated) and possible reservoir discontinuities via a reservoir limit test.
*2.6 Justification
Well 211/14-4 RE is the third well drilled in the Penguin prospect to encounter the Brent sequence. The previous two wells drilled were not tested. In order to evaluate the prospect it is necessary to test the reasonable quality oil-bearing Brent sands. It is also desirable to recover representative formation water samples. Down-hole shut-in is required since the prospect is fairly complex and faulted and early time pressure response data is required to fully evaluate the structure. Conditioning of the well prior to well fluid sampling is of vital importance in this well.
Based on RFT data the prospect is expected to contain oil. The ODT in the Brent sands is estimated to be a 11,630 ft AHBDF.
*2.7 Correlation wells
Gas/condensate has been found in the Statfjord sands in wells 211/14-1, 211/14-3 and oil in 21/14-2, 211/13-2 and 211/13-6.
ODTs have been seen in the Brent sands in the 211/13-2 and 211/13-6 well. 5,142 b/d oil were produced from the Brent unit of 211/14-3.
*2.8 Equipment rating
See Section *2.22 and Section *2.23 - Schlumberger Down-Hole Equipment and Riser Equipment Details. Equipment is all 15,000 psi rated. However, surface pressures are not expected to be more than 6,700 psi. This figure assumes gas to surface at a density of 0.14 psi/ft.
*2.9 Predicted temperatures
Down-hole temperatures are expected to be in the order of 280°F. Maximum recorded temperature during the third run diplog on 15 February 1991, was 258°F.
*2.10 Production rates
All chokes changes will be limited to 4/64" equivalents until the choke size/flow rate relationship is known.
*2.11 Sand production
Continuous sand production is unlikely to occur, based on correlation wells' production tests plus sonic logs. However, 211/14-1 and 211/14-3 both produced sand, up to 5 lb/1,000 bbl during the clean-up after perforating. Standard procedures for sand detection must be adhered to, as per DOM volume 5, and any sand production reported.
As the well is likely to produce some gas (logs may indicate hydrocarbon type), Drexel sand monitoring equipment will be used.
*2.12 References
Drilling Operations Manuals (DOM's) - where not covered above
Wireline Logging and Perforating Manuals
Cameron WSII Wellhead Manual
Production Handbook
*2.13 Responsibilities
As per "Production Testing Responsibilities"
*2.14 Sampling
Throughout the test monitor chloride content of any produced water to determine if it is representative of formation water, also monitor the pH, calcium and magnesium content, as a quality check on the water samples being collected. This is to help differentiate between filtrate, brine and formation water. If formation water is being produced then samples should be taken and the pH, HCO3, CO3 and CO2 concentrations determined on-site immediately after sampling.
If H2S is present, Draeger tubes from H2S monitoring equipment are to be sealed to prevent air ingress and retained for Geochemical sulphur isotope analysis. The minimum requirement is two completely blackened 'A' tubes. An additional water sample taken during the flow period during which the H2S was measured is required if H2S is present. After the production test, all used tubes are to be returned by the Company Production Chemist after ensuring they are comprehensively labelled/documented.
*2.15 Expected well conditions
Upper Bent formation
Maximum expected THP6,700 psi (assumes gas at 0.14 psi/ft to surface)
Reservoir fluidLight oil
Kill margin840 psi
Estimated fracture gradient0.815 psi/ft
Annular kill valve setting3,000 psi annulus pressure
Bottom-hole temperature280°F at TD; 275°F at top Brent reservoir
Gross thickness48 ft
Net thickness39 ft
Average hydrocarbon saturation60%
Average porosity17%
Perforation interval11,484-11,532 ft
Lower Brent formation
Maximum expected THP6,700 psi (assumes gas at 0.14 psi/ft to surface)
Reservoir fluidLight oil
Kill margin840 psi
Estimated fracture gradient0.815 psi/ft
Annular kill valve setting3,000 psi annulus pressure
Bottom-hole temperature280°F at TD; 275°F at top Brent reservoir
Gross thickness32 ft
Net thickness28 ft
Average hydrocarbon saturation50%
Average porosity12%
Perforation interval11,578-11,610 ft
Statfjord formation
Maximum expected THP6,700 psi (assumes gas at 0.14 psi/ft to surface)
Reservoir fluidWater
Kill margin840 psi
Estimated fracture gradient0.815 psi/ft
Annular kill valve setting3,000 psi annulus pressure
Bottom-hole temperature280°F at TD; 275°F a top Statfjord reservoir
Gross thickness15 ft
Net thickness15 ft
Average hydrocarbon saturation5%
Average porosity10%
Perforation interval12,124 - 12,139 ft
*2.16 H2S
No H2S was seen in 211/13-3. However, 4 ppm was seen in a production test of 21/14-1.
*2.17 General preparation
1.Throughout the operation, close liaison and regular meetings are required between the:
-Company Wellsite Drilling Engineer
-Logging Engineer
-Company Drilling Supervisor
-Dan Smedvig OIM
-Company Well Services Supervisor
-Contractor Well Test Supervisor.
The purpose of the meetings is:
-To introduce personnel and establish communication channels
-To discuss safety procedures
-To discuss special circumstances, e.g. weather conditions, well conditions, equipment, etc.
-To ensure all personnel are aware of their duties and responsibilities.
2.Ensure the Well Services and Atlas Wireline's BOP's latest workshop test dates are checked and recorded. On arrival on the rig, all the equipment must be thoroughly inspected to ensure it will be in good working order for use. The Atlas wireline BOPs to be tested using the test jig. Refer to "Wireline BOPs Operation and Testing".
3.The rig will supply steam. The steam will be primed to 100-110°F prior to opening the well. During the flow period this temperature is maintained across the secondary choke and associated down steam lines, to prevent possible hydrate formation. Just downstream of the first choke a temperature sensor is set to trip a an audible alarm when the temperature drops below -20°F, upon which the well will be shut in.
The minimum operating temperature of the separator is 70°F (21°C). The maximum safe operating pressure of the separator is 1,440 psi, normal operating pressure depends per well or zone, but would be 1,200 psi maximum.
4.Ensure sufficient methanol and mono-ethylene glycol are available and applied to avoid hydrate formation at all times. Refer to "Hydrate Prevention". All pressure tests on wireline equipment to be performed with a mixture of 60/40 glycol/seawater. Methanol burns with an invisible flame. The area around the methanol tanks and all areas where methanol could accidentally be released should be covered in salt. If the methanol is then ignited it will ten burn with a yellow flame.
Injection ports are situated in:
-line upstream of the choke manifold, to inject methanol or glycol.
-flowhead between Swab and Upper Master, to inject methanol or glycol.
-between Upper and Lower Lubricator valves, inject methanol only.
-between Retainer valve and SSTT ball valve, inject methanol only.
5.Rig air is not to be connected to the burners for atomisation of hydrocarbons. Mobile air compressors (zone 2 certified) (Section 8.3.2.2) will be used .
6.If flowing a well is necessary with wireline tools in the hole the well is to be opened and beaned up with extreme care and with constant communication between the choke manifold and the logging unit. All choke changes will be limited to 2/64" equivalents until the "choke size/flow rate" relationship is known. The Logging Engineer dictates the maximum flow rate according to the weight loss on the indicator. If a problem does occur the well is immediately shut in at the choke.
7.Sand production is to be monitored throughout bean-up and flow periods, and flow rates adjusted accordingly. Refer to "Production Testing - Flowing the Well".
8.Large volumes of gas may be flowed and a constant check on heat radiation levels is required (meters to be provided by Well Services). Crew members should be briefed on the dangers of high U.V. radiation. The structure must be given maximum cooling and monitored for any hot spots.
The firemains must be pressurised and fire hoses should be manned and laid out to strategic points during the well test.
Ensure that the spray curtains for each burner, the combustible gas and alarms are checked prior to the production test.
BA sets must be available in the test area, mud pits and drill floor, and must be checked regularly.
9.Purge stock tank and maintain a blanket of nitrogen in the tank throughout the test.
10.Rig up a surface annular pressure recorder (24 hour) and a gauge for monitoring annular pressure in the drillers dog house.
Annular pressures are to be monitored continuously by the Schlumberger operator during all flow periods. Ensure pressures do not go outside normal operating pressures for the tools in use. Annulus pressures are to be recorded and reported every 15 minutes throughout the test.
An Annular Kill Valve (SHORT) with a burst disk set to shear at 3,000 psi above the normal hydrostatic annulus pressure, is fitted in the test string.
If a tubing leak occurs near surface, the increase in annular pressure would cause the AKV to open. The kill mud in the annulus will U-tube into the tubing, reducing the annular pressure. The killing will be completed by pumping kill mud down the BOP kill line into the annulus, via the AKV up the tubing.
11.In the event that base oil is being pressurised at surface, ensure that the lines do not contain any air.
12.This well will be tested in water based mud with a gradient of approximately 740 pptf. The weight will be sufficient to kill the well at the top perforation with the riser removed.
13.Lifeboat engines and operating gear should be checked prior to perforating the well.
14.A fire drill must be carried out prior to the production test (assuming a fire in the test area), followed by an evacuation drill (assuming lifeboats close to the test area are inaccessible).
Prior to perforating the well, a H2S drill should be conducted, this must be logged by the OIM (see H2S above).
An emergency shutdown kill pump start-up must be performed prior to the production test.
These drills must be logged in the logbook by the OIM.
*2.18 Communication
All production testing details should be telexed on the Petroleum Engineering telex to the normal addressees with the addition of UEOW/556. The report must be sent on time, e.g. 06.00 hrs and 13.00 hrs. All data relating to the test should be included on the report. The reports should be sequentially numbered. Ad hoc reports may be requested at other times but the information should be repeated on the official 06.00 hrs and 13.00 hrs reports.
All telexes concerning programme amendments initiated either by the rig or in town should be sequentially numbered.
*2.19 Reference log
211/14-4 RE CDL-CN-GR dated 15 February 1991 should be used as the reference log for the test. A complete log will be forwarded to the rig.
*2.20 Programme outline
*2.20.1 Phase 1 - Preparation
1.Run and cement 7" liner.
2.Clean out cement; scrape packer setting depths; condition mud.
3.Run CBL/VDL log.
4.Run 95/8" Hurricane packer. Pressure test casing to 7,500 psi and liner lap to 2,000 psi. Displace drillstring to seawater and perform inflow test.
5.Run 7" Positrieve packer in liner. Pressure test casing/liner lap above to 4,000 psi.
*2.20.2 Phase 2 - Running test string
1.Run gauge ring/junk basket/CCL-GR
2.Run and set an FB-1 packer with 30 ft seal bore extension at 11,300 ft ahbdf.
3.Run and set test string filling with drill water while running.
*2.20.3 Phase 3 - Perforation and Evaluation of Lower Brent Sandstone
1.Make dummy wireline gun run.
2.Perforate inerval 1 (11,578 to 11,610 ft) with wireline guns, under 500 psi static drawdown.
3.Flow well for 15 mins.
4.Shut in and recover guns.
5.Open well and flow clean.
6.Shut in well.
7.Open well and evaluate. Bottom hole samples may be required.
8.Shut in well.
9.Take bottom hole samples.
*2.20.4 Phase 4 - Perforation and Evaluation of Upper Brent Sandstone
1.Perforate interval 2 (11,484 to 11,532 ft) with wireline guns.
2.Flow well for 15 minutes.
3.Shut in and recover guns.
4.Open well, flow clean.
5.Shut in well.
6.Open well and evaluate. Take samples.
7.Shut in well.
8.Perform limit test.
9.Shut in well.
*2.20.5 Phase 5 - Perforation and Evaluation of Statfjord Formation
1.Perforate interval 3 (12,124 to 12,139 ft) with wireline guns.
2.Flow well for 15 minutes.
3.Shut in and recover guns.
4.Flow well for minimum three tubing volumes. Take samples. Monitor BS&W.
5.Run bottom hole samples.
6.Flow well and sample.
7.Shut in well. Recover samplers.
*2.20.6 Phase 6 - End of test
Kill well and pull tubing string. Confirm data has been collected.
*2.20.7 Phase 7 - Abandonment
To be advised.

*2.21 Detailed programme
*2.21.1 General notes
•See Section *2.24 regarding Schlumberger tools - taking special interest in the Notes contained therein.
•Vertical well of angle 3 degrees building to 5 degrees across zones of interest.
•95/8" casing 53.5 lbs/ft P110 VAM thread set at 10,999 ft.
•7" liner 38 lbs/ft SR95 VAM thread set at 12,245 ft. Top of tie back packer at 10,497 ft.
•A summary of Schlumberger tool functions used on this well can be found in Section *2.24.
•Tubing conveyed perforating guns will not be used on this well.
•Run completion allowing the complete inerval 11,484 - 12,139 ft to be logged using Atlas Wireline's PLT tool.
•Packer to be set at 11,300 ft.
*2.21.2 Phase 1 - Preparation
1.Run and cement 7" liner as per "Liner Running Procedures", with 500 ft liner lap. On bumping the plugs, do not apply more than 200 psi surface pressure. Top of liner lap assumed at 10,500 ft.
2.Clean out the liner and PBR as per "Liner Running Procedures". Make up the following assembly:
-53/4" bit
-43/4" Drill Collar
-7" scraper
-53/4" gauge sleeve
-5 ´ 43/4" Drill Colar
-31/2" Drill Pipe
-tieback mill (set so that when the mill shoulders out in the PBR, the bit is at approximately 20 ft above the theoretical top of float collar).
-95/8" scraper
-5" Drill Pipe
-95/8" scraper (so that when the tieback mill shoulders out in the PBR, the scraper is one stand below the mid point of PBR and drill floor).
Check that the wear groove is visible on the gauge sleeve and also check for any cracks.

a)Run the assembly inside the liner hanger. Scrape the 100 ft above and below packer setting depth at 11,150 ft.
Clean out PBR with tie-back mill by stabbing in carefully, rotating slowly and circulating. The lower 95/8" scraper will clean the tie-back setting area at the same time. Observe the slight pressure increase as the tie-back mill enters the PBR and further pressure increase 5 ft deeper as the mill shoulders on the 30 degree chamfer at the bottom of the PBR. Come out of the PBR rotating slowly. Do not enter the PBR with the tie-back mill again.
The Company Drilling Supervisor is required on the drill floor during all operations inside the PBR. Report on all indications of entering the PBR with the bit or mill.
Circulate to condition mud.
3.Rig up Atlas wireline and run CBL/VDL.
4.Run 95/8" Hurricane packer on 5" drill pipe and set at 10,470 ft - approximately 30 ft above PBR. Pressure test the 95/8" casing to 7,500 psi. Pressure test 7" liner lap to 2,000 psi for 15 minutes in LOT mode. Unseat packer and displace drill string to seawater under controlled conditions. Reset packer and perform inflow test on liner lap for one hour to prove decreasing base flow. If in doubt continue test. Circulate back to mud at end of inflow test.
In the event that the liner lap fails a tie-back packer will be run.
5.Run 7" Positrieve packer on 5"/31/2" drill pipe. Ensure 31/2" tail pipe is long enough such that when the packer is set 30 ft below the PBR, the tailpipe is 50 ft above clean out depth in step 2.
Run and set the Positrieve packer 30 ft below the PBR - approximately 11,530 ft. Pressure test the 95/8" and 7" liner lap above the packer to 4,000 psi in LOT mode.
The collapse rating of the inner mandrel of the 7" Positrieve packer is 9,000 psi
The slip force acting on the casing will be below the punch through force for 7" casing.
Run the tailpipe slowly down to clean out depth in step 2 above and circulate the remaining mud to 740 pptf.
*2.21.3 Phase 2 - Running test string
1.Prior to running the test string, prepare tubing and sub-assemblies as per "Production Testing Sub Surface Equipment" and Attachment 1.
Rig up Atlas wireline and make gauge ring/junk basket/GR/CCL run to HUD. Liner is 7" 38 lbs/ft SR 95. Gauge ring size 5.795". Record the CCL over the 7" liner and tie in with the Reference log CDL-CN-GR dated 15 February 1991.
Rerun if there is any junk in the junk basket.
2.Run and set an FB-1 83-40 packer complete with 30 ft seal bore extension at approximately 11,300 ft ahbdf. Reference log GR/CCL step 1 above. Ensure the packer is at least 5 ft from a casing collar. Seal bore extension to be drifted and ID caliper checked and recorded prior to running in hole.
3.Run the test string as shown in Attachment 1 - Downhole Equipment. PCT tool will be run closed. Fill string with drill water as it is run. Gauges will be set in a bundle carrier. Settings have been discussed with gauge supplier.
a)At approximate depth of Sub Sea Test Tree, do not fill with drill water. Continue RIH. Take care not to damage the packer with tail pipe when running test string. Land the G Locator on packer with 10,000 lbs.
b)Rig up and run GR/CCL to confirm Tubing Tally and that Locator has anded by reference to RA sub depth.
c)Rig down GR/CCL close pipe rams on Tubing, open pipe rams and POOH or space out.
d)Calculate space out, such that G. Locator is 12 ft open when tubing anded off. Pick up SSTT and run Landing String, Lubricator Valves and Flowhead. Fill string with drill water.
e)Observing Weight Indicator, enter seals into seal bore and land out SSTT n wellhead. Verify space out.
f)With SSTT and Lubricator Valves open, Pressure Test through kill line, against PCT to 7,500 psi for 15 minutes. (N.B. Pipe Rams to be open).
g)Close SSTT. Bleed off above to 500 psi. Carefully note volume of returns. Observe for pressure increase. After 15 minutes equalise across valve and open SSTT.
h)Close Lower Lubricator Valve. Bleed off above to 500 psi, observe for pressure increase. After 15 minutes equalise across valve and open ubricator valve. Repeat for upper lubricator valve. Open lubricator valve and bleed tubing pressure to zero.
i)Complete remaining Pressure Tests to surface equipment. Close upper ubricator valve. Test Upper lubricator valve via kill line to 9,000 psi rom above. Inflow test all flowhead valves. Repeat 9,000 psi test on both lower lubricator valve and retainer valve.
j)Close Pipe Rams and apply 1,000 psi to the Annulus to close PORT Tool. Hold pressure for a minimum of 5 minutes. Bleed off Pressure.
k)Apply 3,200 psi to Tubing to equalise pressure across Ball Valve before opening PCT valve.
l)Apply 2,000 psi to Annulus to open PCT. Monitor annulus pressure over 15 minutes to test pipe rams around SSTT slick Joint. Cycle PCT to "lock open" position by pressuring up and releasing pressure in the annulus.
2,000 psi required for first opening only. Thereafter opening pressure will be 1,500 psi.
m)When PCT is in locked open position and annulus pressure is zero, increase surface pressure to 5,000 psi through tubing to rat hole to provide 2,000 psi differential from below packer. (Observe annulus for pressure increase). From volumes pumped in test at step 6, it can be determined whether PCT is open.
n)Bleed off applied tubing pressure, to give 500 psi static underbalance.
o)Rig up Atlas Wireline for running wireline guns.

*2.21.4 Phase 3 - Perforation and evaluation of Lower Brent sandstone
1.Make drift run with dummy wireline guns. Make the dummy length as close to the actual as possible to give a realistic trial.
2.Perforate the poorer quality Rannoch sand (lower Brent) - procedure below.
3.Use 21/8", 6 spf Silver-jet wireline perforating guns. Perforate interval 1 (11,578 to 11,610 ft AHBDF Ref log CDL-CN-GR dated 15 February 1991), with wireline guns, under 500 psi static drawdown.
a)Run guns below perforations. Flow well for 15 minutes.
4.Shut in at surface and recover guns.
5.Open well and flow clean at maximum stable rate. Once well is clean and stable, flow at this rate for 6 hours. Monitor sand production during bean ups and choke well back if it exceeds guidelines. The conditioning of the well is very important. Monitor and plot FTHP, FTHT, GOR/CGR, oil/condensate rate, gas rate, BS&W, H2S content and chloride content of produced water. Inform R.E. when stable flow is achieved so that it can be confirmed.
6.Close in downhole, while flowing well, by bleeding off annulus pressure to zero. Close in on surface, monitoring pressure on surface. Closed in period will be 1.5 times total flowing period in step 5.
7.Ensure differential across PCT is not greater than 5,000 psi before opening again. Open well by pressuring up annulus to 1,500 psi.
a)If well is producing oil, flow the well at the maximum stable rate, as seen in step 5 above, for 6 hours. Take samples as per "Production Testing Sub Surface Equipment". If the GOR is in excess of 1,500 scf/stb take two pressurised gas samples per pressurised oil sample from the separator. Take monophase wellhead samples if the well is flowing at a pressure 750 psi above the bubble point of the oil (R.E. will advise). Three monophase samples are required with saturation pressures within 50 psi.
If well is producing gas, flow for 4 hours stable at 30% of maximum rate, 4 hours stable at 60% of maximum, then 4 hours stable at 90% of maximum rate. Take samples as per except take two pressurised gas samples per pressurised oil/condensate sample.
Monitor Chloride content of any produced water. Also monitor pH, calcium and potassium content. If formation water is produced samples should be taken. Monitor pH, HCO3 and CO3 concentrations on site.
If emulsions are produced record flow rate, choke setting and pressures when the emulsions are flowed.
H2S sampling should be undertaken.
8.Close in downhole by reducing annular pressure to zero. Closed in time will be 1.5 times total flowing period in step 7.
9.If required, and if the well is flowing oil, take bottom hole samples. Three samples are required with matched saturation pressures within 50 psi.
*2.21.5 Phase 4 -Perforation and evaluation of upper brent sandstone

1.Perforate the upper (Brent Etive sands) zone with wireline guns - procedure below.
a)Use 21/8" 6 spf Silverjet perforating guns. Perforate additional interval 2 (11,484 to 11,532 ft AHBDF Reference log CDL-CN-GR dated 15 February 1991) with wireline guns, under 250 psi dynamic drawdown.
2.Run guns below perfs, flow well for 15 minutes.
3.Shut in at choke and recover guns.
4.Repeat test as in Section *2.21.4 step 6 and step 7.
5.If the well is flowing gas, proceed as per Section *2.21.4 step 7 and step 8.
If the well is flowing oil then:
a)Open the well to the maximum stable rate established in section 4.4. Flow the well at this rate for 24 hours. Take surface samples towards the end of the period, as per .
Ensure the well is flowing stable when the samples are taken.
-If FTHP > bubble point pressure by more than 750 psi take surface samples.
-Measure any H2S produced during this extended flow period.
-Surface sampling/monitoring guidelines as per and Section *2.21.4 step 7.
-Extend flowing period to complete sampling if necessary.
b)Shut well in down hole for twice the flowing period in step 5.1.
-Run the Schlumberger datalatch tool to interrogate the MSRT and to give real time monitoring at surface of the build up pressures. Fax the following plots to town on a routine basis:
-Horner plot of the build up.
-log-log plots of DP and DT with derivative.
6.Run a PLT across the perforated interval - PLT programme as per Section *2.25.
7.If necessary, and the well is flowing oil, take down hole samples as per Section *2.21.4 step 9.
8.Shut in well at surface.
*2.21.6 Phase 5 - Perforation and evaluation of statfjord
1.Additionally perforate the waterleg of the Statfjord sands.
Use 21/8", 6 spf Silver-jet wireline perforating guns. Perforate additional interval 3 (12,124 to 12,139 ft AHBDF, Reference log FDC/CNL) with wireline guns, under 250 psi dynamic drawdown.
2.Run guns below perfs, flow well for 15 minutes.
3.Shut in well at surface and recover guns.
4.Flow the well for 3 tubing volumes, continually monitoring for BS&W and chlorides content of produced water. Shut in well at surface. Rig up and run 3 single phase bottom hole samplers. Ensure well is flowing at the maximum practical rate when the samples are taken.
5.Shut in well at surface. Recover samplers.
*2.21.7 Phase 6 - End of test
1.Confirm that all data have been collected. Kill well and pull tubing string.
2.Check gauges have recorded all required data, confirm with town to abandon.
*2.21.8 Phase 7 - Abandonment
To be advised.
*2.22 Downhole Equipment, Well 211/14-4, West Stadrill
ItemID (in)OD (in)Working pressure limits (psi)Temperature limits (°F)
InternalExternalLowHigh
*2.23 Schlumberger Riser Equipment, Well 211/14-4, West Stadrill
ItemID (in)OD (in)Working pressure limits (psi)Temperature limits (°F)
InternalExternalLowHigh
*2.24 Summary of tool functions
*2.24.1 Port
The Pressure Operated Reference Tool provides an automatic hydrostatic reference to the Nitrogen chamber of the PCT. It eliminates excessive precharges at surface and guarantees no premature opening of the PCT while RIH.
The second function of the Tool is to provide a repeatable bypass while entering or pulling a seal assembly through the packer seal bore. This feature also allows a Pressure Test to be made against the PCT once landed out in the wellhead and packer with no risk of applied pressure activating TCP guns prematurely.
The PORT will close and string will have to be retrieved should annulus pressure be applied at the wrong stage of the programme.
*2.24.2 PCT
The Pressure Control Tester Valve is the primary downhole shut in Valve. It allows repeated Pressure Testing of the Test string while RIH to 15,000 psi if required. An optional lock open module can be fitted which allows the Tool to remain open with no pressure applied to the Annulus. The lock open feature is multicyclic and operates with no time delay.
Pressure differential for opening and closing this valve should be restricted to 5000 psi.
*2.24.3 SHORT
The Single Shot Annular Reversing Valve is a simple Annular over pressure activated valve which once opened cannot be reclosed.
*2.24.4 MCCV
The Multi Cycle Circulating Valve is a reclosable Tubing operated valve which allows the spotting of fluids or gases.
*2.25 PLT programme
Rig up Atlas pressure control equipment and install PLT toolstring and pressure test to 7500 psi. Tool string is 111/16" with 21/8" spinner cage.
PLT toolstring consists of: CSF/TEMP/GRC/GR/CCL. If the well has been producing water the FCAP and FDC should also be run. Optimum toolstring weight to be based on calculations of critical flow rate.
Run PLT in hole and position the pressure sensor at 11,435 ft AHBDF (± 50 ft) above top perforations). Record CIBHP for 15 minutes. Record and report CITHP every 5 minutes during this period.
Calibrate the spinner by making no-flow passes at various cable speeds up and down between 11,435-11,660 ft AHBDF (± 50 ft above and below the perforations). Logging speeds at the discretion of the Atlas Engineer and the WSOE. (Normally three speeds are sufficient). Ensure that the PLT toolstring does not enter the WEG.
Further calibration passes may be required at the discretion of the WSOE and the Atlas Engineer. If cross flow is observed, additional no-flow passes at variable logging speeds may be necessary in order to quantify the flow. In addition, spinner readings should be taken with the tool at suitable locations between the cross flow zones.
Position the pressure sensor at 11,435 ft AHBDF. Ensure that the top of the tool is at least 50 ft below the WEG. Slowly bean up the well to the stable flow rate established in previous flowing period. Monitor cable tension at all times to prevent tool lifting. Bean back if necessary. Continue flowing until fluctuations in flow rate, BS&W and GOR are less than 10% over one hour.
Record BHP and spinner while beaning up. Record FBHP for 15 minutes prior to flowing passes. Record and report FTHP every 5 minutes during this period.
Record and report all surface production data (Rate, BS&W, GOR, FTHP, etc.) while flowing the well.
Log PLT up and down over the interval 11,435-11,660 ft AHBDF at various speeds. Normally three speeds is sufficient. Ensure that the PLT toolstring does not get within 30 ft of the WEG.
Mufax a quick-look evaluation to UEOW/341/556 as soon as possible.
Additionally, the WSOE is to inform Atlas Engineer that a short summary of any anomalies observed during the PLT logging runs. The digitised data of CIBHP and FTHP over the 15 minute periods, shall be included on the final field print.
Close in the well at surface and retrieve the PLT tool string.
*3 15,000 psi well testing programme
*3.1 Objectives
1.Establish the productivity and determine reservoir parameters for the V3.0 gas bearing interval from 3286.0 m to 3333.0 m ahbdf.
2.Obtain representative reservoir fluid samples for PVT analysis and CO2 determination.
*3.2 Introduction
CP-236, drilled as an exploration well in the Champion field, has encountered significant volumes of hydrocarbons in the exploration prospect. Preliminary petrophysical evaluation indicates 26.8 m of net gas sands in the V3.0 interval. A production test will be carried out on the interval between 3286.0 and 3333.0 m inside the 41/2 liner.
After the production test, the well will be abandoned and a further programme advised.
*3.3 Summary programme
Time est. (days)
1.Scraper trip, pressure test casing and BOPs3
2.Run completion/hook up and test3
3.Production test5
4.Kill well and pull completion3
* Abandonment programme to be advised14
*3.4 Non standard and/or potentially hazardous operations
Testing of wells is generally considered to be the most hazardous operation in the drilling industry because hydrocarbons are brought to surface, an operation which is normally avoided during drilling operations. The CUD test will produce from a formation with very high pressures (70,000 kPa (ca. 10,000 psi) at 3285 m, gradient 21.3 kPa/m). Maximum expected closed in tubing head pressure is ca. 58,400 kPa (8500 psi).
The philosophy during the planning stages of this test has been to keep the completion string as simple as possible and to minimise wireline work.
This has resulted in the following:
•TCP guns will be used, to be fired with a drop bar;
•only three wireline runs are required to test the tubing string and one drift run to confirm that the TCP drop bar can pass through the string;
•downhole gauges will be installed in carriers above the packer and run and retrieved on tubing;
•the tubing will be run with a plug installed;
•oil based mud will be used as a packer fluid.
Enhanced safety features are:
•a tubing retrievable subsurface safety valve will be run in the string;
•the BOPs will remain in place during the test and the well will be controlled via a 15K surface flowhead;
•a shearable joint will be spaced adjacent the shear rams;
•two annular pressure operated circulating devices (SHORT tools) are included in the string.
Refer to safety notes in Section *3.17.
*3.5 Well data
*3.6 References
*3.7 Equipment mobilisation
1.Part of the Flopetrol production testing equipment (separator, HP lines etc.) has already been installed on the rig.
The mobilisation of the remainder of the Flopetrol production testing equipment, (test tree, steam exchanger etc.) will be organised by OPD/212. Onshore testing of this equipment in preparation for the production test will have been witnessed by a representative from OPD/212.
2.In addition to the Flopetrol production testing equipment OPD/212 will provide the following:
a)Tri-ethylene glycol (TEG) for circulating into the test string before opening up the well. (Acid type bulk transport tanks).
b)Mono-ethylene glycol (MEG) for injecting into the surface flowline upstream of the choke and the Schlumberger lubricator (200 l drums).
c)Methanol for injecting into the line upstream of the choke manifold should a hydrate plug form (200 l drums).
d)All completion string accessories.
e)All wireline equipment.
See handling data for above mentioned chemicals in Section *3.17.
3.The BSP Drilling Supervisor has overall responsibility for the test equipment. Specific attention should be paid to organising the following items:
a)The test string. This will be a string of 88.9 mm (31/2) L80 Hydril PH-6 above the packer. A string of 27/8 6.4 lbs/ft L80 VAM is run from below the packer to the top of the TCP-string.
b)Baker production packer and seal assembly.
c)Propane for burner pilot lights.
d)Vetco Gray tubing hanger.
4.The WSOE is to ensure that the following are onsite:
a)Perforating guns.
b)Sample bottles and cans.
c)Pressure gauges.
*3.8 Programme outline
*3.8.1 Preparation
Make seven casing scraper trip/pressure test BOPs and THS
*3.8.2 Production test V3.0
1.Set production packer
2.Run completion string with TCP guns
3.Perforate interval
4.Clean up well. Close in
5.Flow well at maximum stable rate. Close in
6.Flow well at minimum stable rate
7.Flow well at 70% of maximum stable rate
*3.8.3 Kill well
1.Kill well
2.Pull completion string
3.Abandon V3.0 interval
*3.9 Running completion
Nom. sizeSize (mm)Weight (kg/m)GradeConnection typeAPI driftWireline driftMake-up torque (Nm)
OD ´ length (mm)OD (mm)minoptmaxi
31/288.923.51L80Hydril PH-661.5 ´ 1067N/A745083809310
27/873.09.52L80VAM59.6 ´ 106758.5293032403550
*3.9.1 Pressure testing
Tubing and wireline equipment70,000 kPa
Annulus- kPa
Packer14,000 kPa
Surface Equipment
Upstream of choke manifold70,000 kPa
Choke manifold to heater34,500 kPa
Heater to Oil and Gas Manifolds9,900 kPa
Test Separator8,275 kPa
Downstream to burners6,200 kPa
*3.9.2 Running the completion string
*3.9.2.1 Background information
In the completion string design two methods of establishing communication between tubing and annulus have been incorporated.
1.Method 1: By pressuring up the annulus and shearing a rupture disc in the SHORT-tool. (Two SHORT-tools are incorporated in the string, one as back-up).
2.Method 2: By picking up the completion string and unstabbing from the packer. This method should only be considered if method No. 1 cannot be used.
In order to be able to pick up the string and keep full control of the well, the following features have been incorporated:
•The BOPs will remain in place. With the string landed off, a slick joint (incorporates controlline and prevents it from being crushed by the rams) will be located opposite the pipe rams and a shearable joint opposite the shear rams.
A similar set of joints is located below the hanger to provide the same control when the string is unstabbed from the packer.
•The test tree will be hung off in slings in order to prevent its weight from buckling the joints below.
The anticipated string movements are as follows:
•The string will shorten ± 1.6 m immediately after perforating.
•The string will expand between 1.8 m and 3.0 m while producing, because of the high mud gradient.
Based on foregoing, the seal assembly should enter 3 m into the packer bore and the string should be spaced out such that a 7 m stroke is possible.
After abandoning 35/8" hole proceed as follows:
1.RIH with 57/8" (149 mm) bit and 7" (178 mm) scraper assembly. Scrape across packer setting depth.
2.Suspend string on Plug Type Tester. Change BOP pipe rams in #3 cavity to 5" (127 mm). Make up lower kill hose to THS. Ensure that the hydraulic valve arrangement is properly supported. Pressure test BOPs to 70,000 kPa.
3.Reconnect string. Retrieve plug type tester. Circulate well to 22.4 kPa/m LTOM. Condition mud until weight is even and until the following properties are achieved:
PV = 50 - 60, YP = 10, Gels = 5-10/10-20, OWR > 90/10.
POH scraper assembly.
4.Run Cup Type Tester. Pressure test THS SOVs to 70,000 kPa.
5.Make up the test tree on the top two flow riser joints (see Fig. 1960 and Fig. 1961). Lay down on deck.
6.RIH Baker FB-2 retainer production packer on drill pipe to packer setting depth at ca. 3120 m. Choose packer setting depth to suit space-out of 27/8"tubing relative to perforations with reference to seal assembly spaced out 3 m into top packer (see Fig. 1962). Avoid setting packer sealing elements within 1.5 m of a casing collar.
7.Rig up Schlumberger pressure control equipment and pressure test to 70,000 kPa. Run GR/CCL through drillpipe to adjust the packer setting depth to suit the TCP tailpipe. Rig down Schlumberger.
Set packer as follows:
-Drop ball and pressure up to 10,500 kPa in stages of 3500 kPa. Hold pressure at each stage for one minute.
-Pressure up to 14,000 kPa and hold pressure for five minutes.
-While maintaining 14,000 kPa on the packer pull up 3500 to 4500 daN (8000-10,000 lbs) tension.
-Release upstrain and bleed off pressure.
-Set down 9000 daN (20,000 lbs) and pressure test annulus to 14,000 kPa to check if packer has set, monitor for returns through drillpipe.
-Pressure up via drillpipe to 17,500 kPa - 21,000 kPa to blow-out ball seat.
-Release setting tool. Circulate and condition mud. Check properties are as per step 3. POH and rack back drillpipe in the derrick on Port side.
8.Run TCP guns (27/8", 38C Hyperjets, 6 spf, 60° phasing), locator seal assay (Baker 80-40 LE-22) and test string with accessories installed as per Fig. 1962.
•Run the cone-type debris circulating sub one joint above the firing head.
•Run 27/8" (73.0 mm) XN-nipple just above debris circulating sub.
•Run 58.5 mm (2.302") drift to 27/8" XN-nipple prior to making up seal assembly. Drift tool to bottom out in XN-nipple to prevent accidental firing of TCP during drift run.
•The locator seal assembly/R-nipple connection will have been made up and pressure tested to 70,000 kPa in the workshop prior to shipment to the rig.
•Place radioactive tag in connection one joint above R-nipple.
•A PRN plug and prong will be installed in the R-nipple in the workshop. Confirm the plug has been tested from below to 50,000 kPa/15 min.
•Equip the gauge carrier with 2 FHPR electronic memory gauges and 2 ´ 15 K Ameradas.
•Set gauges as follows:
-FHPR 1:
-delay time to be established on site from running the gauges to just before perforating (discuss proposal with OPE/11 and /1).
-pressure sampling frequency: 30 seconds.
-temperature sampling frequency: 60 seconds.
-FHPR 2:
-no delay. Check gauge is operational before running in hole.
-pressure sampling frequency: 60 seconds
-temperature sampling frequency: 120 seconds.Ameradas: 2 ´ 180 hours clocks
•The bottom and top "SHORT" valves are to be equipped with "Z" type shear discs. At 110°C BHT, these disks will shear at an absolute pressure between 84,000 and 88,200 kPa. This corresponds to 14,800-19,000 kPa surface pressure in the annulus with 22.4 kPa/m mud.
Have a three joint separation between the "SHORT" subs.
•Fill the string with DMA from firing head to perforated pup joint.
Above the plug in the R-nipple fill the string with 5 m3 of tri-ethylene glycol (TEG). Fill the rest of the string with seawater.
9.Run assembly on 31/2 tubing to ca. 1700 m. Pressure test tubing to 70,000 kPa/15 mins.
Use thread compound sparingly on connections. It is essential to keep the completion string clean to allow recovery of the PRN plug.
10.Continue running the assembly on tubing until the bottom of the locator seal assembly is 2 m above the packer. Exert extra care when stabbing the TCP guns through the packer bore.
•Do not make any attempt to stab in at that point because pressure lock would tear out seals.
•Do not install SSSV at this stage.
11.Rig up WLS lubricator and pressure test to 40,000 kPa. Run 2.302" (58.5 mm) drift to the "R-nipple". Rig down WLS.
12.Pressure test tubing to 70,000 kPa/15 mins.
13.Rig up Schlumberger pressure control equipment and pressure test to 40,000 kPa. Run GR/CCL down to the radioactive tag. Determine space out. The bottom of the locator seal assembly to be located 3 m into the packer when the tubing hanger is landed in the tubing head spool.
14.Pull back the tubing to the safety valve setting depth (ca. 50 m below sea bed, 122 m bdf).

15.Install the safety valve with control line.
-The 1/4" control line should be filled with Tellus-46 oil and pressure tested to 100,000 kPa. The complete reel of control line should have been flushed with Tellus-46 before being run. Maintain 14,000 kPa pressure on 1/4" control line during running so that any possible leaks can be monitored and rectified immediately.
-Secure control line with two bandites on every full joint, one on every pup joint.
-The correct tension is applied to the control line using the WLS sheave assembly.
-It will be necessary to cut the control line at each connection to the slick joint.
-Wrap the control line once around the tubing below hanger at each slick joint.
16.Continue running the tubing as per diagram until the bottom of the locator seal assembly is 2 m above the packer. This results in the long flow riser joint sticking up ca. 2 m above the rotary table.
The slick joints and hanger will be shipped out in two sub assemblies which have been made up and pressure tested to 70,000 kPa in the workshop.
The slick joints are spaced out in such a way that:
•Upper slick joint: with the string landed, the upper slick joint is located opposite the 5" #3 pipe rams (a 31/2" pup joint is then be located opposite the #2 shear rams).
•Lower slick joints:
-it is possible to pick up the string until the lower slick joint is located opposite the 5" #3 pipe rams;
-when the slick joint is located opposite the 5" #3 pipe rams, the seal assembly is fully out of the packer seal bore.
Take care when the lower slick joint passes through the 7" casing hanger. The control line termination bosses could hang up.
17.Make up the test tree with the two riser joints to the string. (Top of test tree ca. 10 m above derrick floor). Tree to be hung off in slings to avoid buckling the shear joint. Rig up kill and flow lines flexible hoses.
•Do not let the test tree stand free at any time.
•Use safety clamps on the 61/4" heavy wall tubing.
18.Pressure test tubing, test tree, kill and flow lines to 70,000 kPa/15 min. Pressure test control line to 100,000 kPa/15 min. Bleed off control line pressure to close the SSSV. Bleed off tubing pressure above SSSV. Inflow test SSSV for 15 minutes. Equalise pressure across SSSV. Open SSSV by applying 60,000 kPa pressure on the control line. Bleed off tubing pressure. Maintain 60,000 kPa on control line to keep valve open.
19.Rig up WLS on top of the test tree and pressure test same to 70,000 kPa. Run a 2.302" (58.4 mm) drift to the bottom R-nipple. Pressure up tubing to ± 43,000 kPa to provide 1300 kPa differential pressure from above across the plug. Pull the PRN prong and plug from the R-nipple.
20.Displace string with ± 0.3 m3 of seawater to chase out mud between R-nipple and perforated pup joint.
21.Slowly lower the tubing until the seals have entered the packer bore. An increase in pressure on the tubing will be observed. Lower the tubing while maintaining the observed pressure on the tubing.
22.Land off string and bleed off pressure in stages. Observe for flow, indicating that either the seal assembly, or the casing below the packer (or the cement plug/EZSV) is leaking.
23.WLS rig up pressure control equipment and pressure test same to 70,000 kPa. Make 58.5 mm drift run to the 27/8" XN-nipple to ensure drop bar (OD 13/8" (34.9 mm) will pass the string. Drift tool to bottom out in XN-nipple. This is to prevent accidental firing of the TCP guns during drift run.
If the drift run is unsuccessful and the tool stands up in mud that entered the string in item 18, a Nowsco coiled tubing clean-out trip will be considered. A separate amendment will follow with coiled tubing set up, procedures etc.
24.Run in the tie-down screws.
25.Close pipe rams #3 around slick joint.
26.Pressure test hanger to 70,000 kPa/15 mins from above against pipe rams. Observe volume pumped, bleed off immediately if excess volume is pumped. Maintain pressure in annulus and monitor during the test.
27.Ensure all surface lines and equipment are correctly rigged up and pressure tested as per pressure test values.
*3.10 Production test
•Pressurise the tubing - 7" casing annulus to 2000 kPa and monitor continuously. Install chart recorder. A pressure of ca. 15,000 kPa on the annulus will open the "SHORT" valve and will cause the test to be aborted.
•Report test parameters as per Section *3.18.
•Hydrates prevention: Inject MEG upstream of the choke manifold while flowing the well until the FTHP has reached ca. 75°C which should then be sufficient to prevent hydrate formation. An initial rate of 30 liters/hour should be used. At the end of a closed-in period, start injection at the same rate half an hour prior to opening up the well.
TEG will be used initially to fill up the string and may be used as a back up, should MEG injection prove insufficient.
1.Pressure up the tubing to 30,900 kPa to provide a 3500 kPa (500 psi) drawdown.
2.Hold safety meeting. Timing of the perforation should be such that first hydrocarbons will reach surface in daylight.
3.Rig up Schlumberger pressure control equipment with drop bar installed in tool catcher and pressure test to 70,000 kPa. Drop bar to fire the TCP guns. Close swab valve and leave Master Gate valves open (well closed in at choke manifold). Observe for indications of gun firing.
If gun has not fired, contact base. The drop bar will have to be fished before the guns can be pulled. A separate amendment to follow.
4.Produce well clean at maximum rate via overboard line. Check for H 2S as soon as first hydrocarbons reach surface. If the concentration is greater than 0.5 ppm, close in and contact base. (Presence of H 2S is unlikely, no H 2S was present in RFT sample). Switch to separator when well is sufficiently stable.
Flow well until a maximum stable production rate is achieved for a period of two hours. Stable flow is defined as follows:
-THP fluctuating by less than 0.2% over an hour;
-Separator Pressure, OGR and BSW not varying by more than 2% over an hour.
Obtain confirmation from base before closing the well in.
Take two sets of surface recombination samples at the end of this period. (See Section *3.19 for sampling procedures). Take water samples as per Section *3.19.
•The maximum production rate may be constrained by sand production. Monitor erosion probe and if necessary bean back until sand free production is achieved.
•Do not initially exceed a drawdown of 7000 kPa at surface (i.e. CITHP-FTHP < 7000 kPa). This drawdown is likely to be increased once a production rate has been established. Confirm with base.
5.Close well in at choke manifold for 1.5 times the total flowing period to monitor build-up.
6.Flow well at maximum stable rate as established in item 3 for 12 hours.
7.Close well in at choke manifold for two times the flowing period.
8.Flow well at minimum stable rate. Once stable rate has been achieved (see step 3), take four sets of surface recombination samples at the end of this period.
9.If the maximum rate exceeds 500,000 m3/day, flow the well for four hours at 70% of the maximum rate established in step 3.
10.Close well in for one hour.
11.Confirm with base that test has been completed.
*3.11 Kill well and retrieve completion
1.On completion of the V3.0 test bullhead 22.4 kPa/m LTOM mud to the perforations, not exceeding 70,000 kPa initial surface pressure. Overdisplace the volume to the bottom perforation by 5 m3.
2.Bleed-off tubing pressure and observe well dead. If well is dead, continue with step 3. If gas persists, squeeze further 5 m3 of mud. If the well is still not dead, pressure up annulus to 14,000 kPa (2000 psi) or 21,000 kPa (3000 psi) to open the bottom and top SHORT valves resp. Circulate gas free. Observe well dead. (Annulus and tubing).
3.Undo tie-down bolts and pressure test hanger from above to 70,000 kPa.
4.Open 5" #3 pipe rams.
Pick up string until lower slick joint is located opposite 5" #3 pipe rams. Close pipe rams on lower slick joint. Circulate well over the choke until no hydrocarbons are returned.
Open up and observe well.
5.Pump out of hole over the first 500 m. Flow check. POH completion string and recover pressure gauges.
•Rack back tubing in the derrick.
•Confirm that all shots have fired. Download gauges data and confirm that data is good. Contact base if not.
*3.12 Well status
*3.13 Reservoir and test data, perforation intervals
*3.14 Completion string
*3.15 Production test equipment surface layout
*3.16 Responsibilities at the wellsite
*3.16.1 Personnel
*3.16.1.1 The Drilling Supervisor (DS)
The Drilling Supervisor is in overall charge and coordinates and monitors the operations and should keep himself fully informed of the progress of the test at all times. He must be advised by the Wellsite Operations Engineer (WSOE) before the well is perforated and by the Well Services Supervisor (WSS) before the well is opened up and at any time a potentially hazardous situation may occur. He in turn will inform the WSOE and WSS of any activity or occurrence which could affect the production operations.
*3.16.1.2 The Wellsite Operations Engineer (WSOE)
The Wellsite Operations Engineer is responsible for ensuring that the requirements of the test programme are met. He keeps a tally of everything that is run in to the well. He is responsible for logging, packer setting, perforating, stimulating and PVT sampling, collection and reporting of data, labelling and dispatching of samples.
*3.16.1.3 The Contractor Toolpusher
The Contractor Toolpusher is responsible for the rig and overall rig safety at all times and is the central point of authority. He is ultimately responsible for the safe execution of all operations on the rig including welltesting and abandonment. He should be familiar with the test programme and be involved in the decision making process if changes are necessary.
*3.16.1.4 The Well OPD Services Supervisor (WSS)
The Well Services Supervisor is responsible for preparation and checking of test equipment, wireline work, opening up, beaning up, blowing off and the testing of the well. He is responsible for the safety precautions on the surface production facilities from wellhead to flare. He ensures that an accurate record is kept of all information requested in the testing programme.
*3.16.1.5 The Production Technology (DPT) and/or Reservoir Engineering (DRE) Representative
DPT and/or DRE representative shall be present during production testing in an advisory capacity. He will advise on the duration of flowing and build-up periods and with prior agreement of basemay shorten or lengthen either.
*3.16.2 Other reporting relationships
The Schlumberger Engineer reports directly to the WSOE and only the WSOE should give instructions to this contractor. DPT/4 personnel report to the WSOE.
Well Testing contractor personnel report directly to the WSS. Wireline crews carry out wireline operations as per the programme under the control of WSS.
All requests or instructions to personnel of the drilling contractor from WSOE and WSS should go via the DS unless otherwise agreed.
*3.16.3 Programme changes
Should circumstances arise which may require a deviation from the test programme, the DS and WSOE will advise Base. The Rig Superintendent, Operations Engineer and Completions Supervisor will discuss the problem and jointly agree on the necessary remedial action. On no occasion may rig personnel deviate from the programme unless an emergency arises or prior agreement from base has been obtained in the manner described above.
*3.17 Safety
A safety meeting should be held prior to carrying out the production test programme. The following staff should be present:
•Drilling Supervisor
•Drilling Contractor Toolpusher
•Wellsite Operations Engineer
•Drilling Contractor Barge Engineer
•Well Services Supervisor
•Wireline Co. Rep.
•DRE/DPT Rep.
•Driller
.mud technician
•Flopetrol Downhole Co. Rep.
•Flopetrol Co. Rep.
•Nowsco Rep.
•Schlumberger Rep.
•Camco Rep.
The purpose of this meeting is to:
•Introduce people and establish communication channels.
•Discuss the Production test programme and objectives.
•Discuss special circumstances during the test, e.g. Well conditions and products, equipment performance, contingency plans, etc.
•Ensure that all personnel are aware of their duties and responsibilities.
•Discuss Work Permit requirements.
During this meeting, reference must be made to:
•Safety procedures for using explosives in drilling/completion operations.
•Safety procedures for handling of hazardous chemicals in use.
•Monitoring of toxic gases which may be produced during testing, e.g. H2S.
•Restrictions on other rig activities, e.g. flights, refuelling, welding, standby boat.
•Procedure for well killing.
The WSOE should take minutes of the meeting and copies sent to the Operations Engineer and Rig Superintendent.
The following safety rules will be observed:
1.Work areas around test tree and separators should be kept clear and clean and there must be unobstructed access to these areas at all times.
2.When work is to be carried out on the test tree, a suitable platform should be erected.
3.Always check that the correct number of turns are made when closing valves on the test tree.
4.Keep sufficient volume of kill mud.
5.The Rig kill line should be tested and the non-return valve checked to ensure that it is not leaking.
6.All testing and kill equipment must be tested with a pressure above the maximum pressure that can be anticipated during the operations.
7.The flare ignition system should be checked and an emergency flare ignition system should be available.
8.Blowing off should be possible on either side of the rig.
9.A blow-out, abandon rig, and man over board drill to be held prior to flaring off operations.
10.Welding will not be allowed during the production test.
11.The fire fighting system should be under pressure before starting of flaring off operations.
12.Check safety shut in system and note the time it takes before the safety valve is fully closed.
13.Gas explosion meters, hydrogen sulphide detector and portable breathing apparatus sets must be available. All key personnel to be familiar with the equipment operation. As soon as possible the gas must be checked for H 2S by Flopetrol.
14.Flopetrol personnel are wholly responsible to the Well Services Supervisor for opening and closing the test tree valves at all times, including during wireline operations.
15.Hang a warning sign on the test tree whenever wireline are in the hole. The purpose of this sign is to prevent the accidental cutting of wires.
16.The Well Services Supervisor to check with the WSOE/Drilling Supervisor about times of and duration of flaring.
17.Shipping and aircraft to be informed to stand clear while blowing off. Helicopter flights must be cleared by Company toolpusher on site before leaving shore base.
STS + SAV to be informed of all flaring operations (by telex).
18.The initial perforation of the well must not be carried out if first hydrocarbons will not reach surface in daylight. After the initial flow period, production testing may then continue into the night.
Test run with diesel oil to check burners, ensure watercooling and spray system working properly.
19.All lines to be properly secured, including relief vent lines. Ensure relief lines cannot be closed off with a valve.
20.Driller and two floormen to be on the derrick floor or wellhead area at all times during test, derrick man in the pumproom.
21.At least two production testing Flopetrol operators required on shift at all times during testing.
22.If a pressure of more than 5000 kPa is observed on the casing/tubing annulus, the pressure is to be bled off and the annulus pressure checked for rate of build-up. If the annulus pressure cannot be bled off the test will be stopped, and leak further investigated.
Note that the SHORT valve opens at 15,000 kPa.
23.Tubulars may be laid down from the derrick, this will be advised.
24.The drilling contractor is to provide four self contained positive pressure breathing apparatus systems, suitable for use in an H2S or explosive gas environment.
25.No smoking is permitted outside the accommodation.
26.There should be at all times on the rig floor a circulating valve with a 31/2" (88.9 mm) PH6 pin and a 2" (50.8 mm) WECO union on top, to enable circulating the tubing whenever necessary during running. (Note however tubing will be run with plug installed).
27.Ensure drillers and assistant drillers know how to close the flowhead master valve and SSSV in an emergency.
28.Rig air must NOT be used to drive the burners. Independent air compressors must be provided capable of sustaining the required flowrate. These must not be tied-in to the rig air system, i.e. the pipework shall be totally independent.
29."Guidelines for Production Testing Operation" will be available on site for reference.
30.Chemicals handling
-Methanol: See Fig. 1966 (chemical data sheet). Methanol is toxic to marine life and all efforts must be made to avoid spillages.
-TEG and MEG: Given routine precautions (i.e. goggles, gloves, coverall) no extra precautions need be taken with these substances. In case of spillage, flush with copious amounts of water.
Figure 1966:Methanol
*3.18 Reporting requirements
All comms should be numbered in sequence and the following should be stated at the beginning of each telex.
Well number
Test interval (i.e. perforated interval)
Test number
Sheet number (Sequence number)
From (i.e. start date and time for following telex)
To (i.e. end date and time for following telex)
*3.18.1 During Production Periods
The following data should be recorded in 30 minute intervals and at bean changes.
A: Time
B: Gas production (m3/day)
C: Flowing Tubing Head Pressure (kPa)/Flowing Tubing Head Temperature (°C)
D: Choke Size (1/64 nominal size [1/64"])
E: Specific Gas Gravity
F: Cumulative Gas Production [or Cumulative Oil Production (m3)]
G: Condensate Production (m3/day)
H: Condensate Gravity (kg/m3)
I: Condensate Gas Ratio (m3/m3)
J: Cumulative Condensate Production (m3)
K: Water Production (m3/day)
L: Water Salinity (ppm)
M: Separator Pressure (kPa)
N: Separator Temperature (°C)
O: H2S (ppm)
P: CO2 (ppm)
Q: BSW
*3.18.2 During close-in periods
The following data should be recorded in 30 minute intervals.
A: Time
B: THP (kPa [gauge])
C: THT (°C)
Report gauges data immediately after running in hole. Exact depths, start time, sampling rate, expected end of recording).
*3.18.3
Report gauges data immediately after running in hole. Exact depths, start time, sampling rate, expected end of recording).
*3.19 Sampling procedure
*3.19.1 Surface samples
*3.19.1.1 PVT recombination samples
Separator samples always consist of a matching pair; a sample from the gas and a sample of the liquid phase, because the composition of both phases is strongly dependent on the flow conditions, care is necessary to ensure that the gas and liquid samples are taken under stable conditions, preferably simultaneously. Sampling lines have to be kept as short as possible.
a. Separator gas samples: Vol: 20 litres
The sample bottle will be evacuated onshore. The vacuum pressure will be checked on the rig. Max. allowable 10 mm Hg. Hook up as in Fig. 1. Open the separator control valve to pressurise the sampling line. Close the separator sampling valve. Loosen the connection above the top valve to purge the sampling line. Repeat this five times. Secure connection. Open the separator sampling valve and allow the pressure to stabilise. Open the top valve slowly. Fill the bottle (20/30 mins). Close the top valve. Close the separator sampling valve. Bleed off pressure in sampling lines.
b. Separator oil/condensate samples: Vol: 600 CC
At the same time as the gas is being sampled, hook up the liquid sampling bottle as in Figure 2.
The oil/condensate sample container must be completely filled with mercury. The bottle must be kept vertical throughout sampling.
•Flush the sampling line with fresh separator liquid through valve A. Close valve A.
•Open valve B, then C and flow at least five times the sample line volume to purge the line. Close valve C.
•Open valve D above the sampling bottle and allow pressures to stabilise.
•Very carefully open valve E such that no appreciable pressure drop is indicated on the gauge at valve E. Slowly open the needle valve F, ensuring that there is not appreciable pressure drop.
•Displace slowly about 85% (500 CC) of the mercury from the bottle with separator liquid while the pressure remains constant.
•Close needle valve F, wait a few minutes for pressures to stabilise, then close valve D. Close the separator sampling valve and bleed off the sampling lines via valves A, B and C.
•Slowly re-open needle valve F (with all other valves closed) and allow a further 8.5% (50 CC) of mercury to drain into the measuring cylinder to create a gas cap to accommodate any expansion during transportation. Close valve E.
*3.19.1.2 Water samples
Sampling for water should be carried out during the production period immediately after the initial perforation has been seen to clean up. Nominally this will be two tubing contents. If sufficient water is not recovered, or the well does not flow after initial perforation, the sampling may then be carried out at any other time when the well is deemed to be clean.
If persistent water cut is observed during a test then more representative water samples should be taken towards the end of the stable flow period(s).
The general water sampling procedure is as follows:
•Crack open the separator drain valve and flush the tube to ensure it is clean.
•Insert the tube into the plastic sample bottle and fill up bottle. After filling, allow several volumes of the water to be displaced from the sampling bottle before removing the sampling tube from the bottle. Fill the bottle completely.
a. Analysis of water samples
WSOE to carry out/supervise the following analysis on one of the water samples taken, as well as on seawater sample to identify potential contamination of samples.
•chloride ion content;
•calcium ion content;
•determination of pH of the produced water;
•density;
•resistivity.
*3.19.1.3 Down hole samples
Bottom hole samples are not required during this production test.
*3.19.1.4 Sampling requirements
The number and type of samples required will be specified in the main production test programme.
*3.19.1.5 Separator sampling details
Well:
Test: Producing Intervals:
Date Sampled:
Time Sampled:
Sample Number:
Bottle Volume:
Bottle Content:Oil/Condensate/Gas
Oil/Condensate Flowrate:m3 at oper. cond.
Gas Flowrate:m3 at oper. cond.
Watercut:(%)
FTHP:(kPa [gauge])
FTHT:(°C)
Separator Pressure:(kPa [gauge])
Separator Temperature:(°C)
Oil Density:(g/ml) at (°C)
Gas Gravity:(rel. to air) at (°C)
Water Density (g/ml):
Water Salinity (NaCl equiv.):
Shrinkage Factor:
GOR:(m3/m3)
Final Bottle Pressure:(kPa [gauge])
Final Bottle Temperature:(°C)
Sampled by:
Witnessed by:

1 Introduction

It is usual to contract out Well Testing Services, including the inspection, testing, drifting of equipment in base workshops and on site.

The effort and time spent to ensure the integrity of each individual component used downhole and on surface will impact on the success of a well in minimising downtime. The thorough inspection on site, before and after use is strongly recommended.

2 Subsurface equipment

2.1 Tubing

When testing to 5000psi, it is generally sufficient to use tubing that is the preferred type used in most completions, e.g. 31/2" New Vam 9.2 lbs/ft L80. In pressures beyond 5,000 psi, the 31/2"Hydril PH6 15.8lbs/ft C95 is preferred, due to the halved number of connections (versus threaded and coupled) and its historically proven make and break repeatability.

Due to the uncertain nature of well testing in terms of pressure and temperature, it is recommended that the chosen tubing connections be of a type tested to API 5C5.

2.2 Accessories

Each accessory has critical design dimensions and is put in string to carry out a specific function. For reasons of simplicity, it is important to incorporate only those accessories that are required to perform a function, e.g.XNlanding nipple to land ameradas. Back-ups are not required due to the temporary nature of the string.

2.3 Xmas tree

The term Xmas tree here is taken to mean generically, and includes subsurface and surface Test Trees. The choice of tree will usually be dictated by the pressure regime it will operate in the location of the well. Most land operations can tolerate a conventional X-tree. A floater for example will have a subsurface and surface test tree complete with swivel to accommodate wave and tide motions. As these items are the principal pressure vessel that would contains full well pressure in any ESD situation, extreme care must be taken in its selection, preparation, testing, transportation and ESD accessories, e.g. actuators.

3 Surface equipment

A list of equipment downstream of the Xmas tree to the burners is given in Section 2. It is generally the norm to hire such equipment from the principle contractor awarded the testing contract. Particularly in Single String Ventures, all equipment is loaded on the rig prior to being moved on site. It is important to carry out full W.P. (working pressure) tests already at this stage, as there are no time constraints, personnel safety is enhanced and any defects can be rectified in time. It is also possible that equipment and rig deck space are a mismatch in ensuring recommended safe distances between, for example, separators and heat exchangers. Such problems can only be rectified if time is not a constraint.

4 Certification and documentation

It is increasingly becoming mandatory to comply with Governmental legislature pertaining to methods of ensuring that tools, equipment and materials conform to international or regional manufacturing standards such as BS5750 (part1), ISO9001, etc.

In the main, API have existing standards that cover virtually all surface items, e.g. separators. Very little however exists for subsurface items, e.g. nipples, SSD's.

It is recommended that all pressure vessels be certified for use by accreditation bodies such as DNV, Lloyds, etc. on a regular basis, e.g. 5 years on separators. It is expected that all such certification and documentation will be readily available for verification if called upon prior to a well test.

5 Workshop

Most OPCOS have excellent workshop facilities that are able to handle all types of preparatory work required to be done prior to shipment to site. These would include functional checks, drifting, hydrostatic testing of assemblies and components, etc.

As far as is practical, equipment should arrive on site at the rig, in a ready to run/use condition where only final measurements, tallying, checks are made.

6 Material standards

6.1 Types of corrosion in oil and gas production

Corrosion problems which may occur in drilling for and production of oil and gas may be caused by:

1.sweet corrosion;

2.sour corrosion.

6.2 Sweet corrosion

Sweet corrosion is caused by carbondioxide (CO2) which dissolves in the accompanying water phase and lowers the pH results in a highly corrosive environment. It can cause either a uniform type corrosion or pitting (ringworm corrosion). Carbon dioxide corrosion is unlikely to occur when the CO2 partial pressure is lower than 7psi. The partial pressure is determined by multiplying the volume percentage of CO2 by the gas pressure in the system.

Since production testing is usually of short duration, sweet corrosion is considered of little importance here.

6.3 Sour corrosion

Sour corrosion is caused by the presence of H2S and water in the production stream:

1.Hydrogen sulphide stress cracking: this type of corrosion causes cracks in the material which eventually fails under load or internal stress; failure may occur at any time during the working life of the material, in some cases immediately after it is put into service.

2.Embrittlement: the hydrogen derived from the hydrogen sulphide by chemical reaction embrittles the material, causing failure to take place within a short time, even in a matter of hours.

3.Uniform corrosion: the surface of the metal is attacked in a fairly uniform manner, with occasional pitting.

The destruction by hydrogen occurs when the partial pressure of H2S in the gas is higher than 0.0142psi. H2S stress corrosion occurs in steels having a hardness higher than Rc22 (237 Brinell). In cases where high residual stresses are present it is possible for H2S stress corrosion to occur at harnesses less than Rc22. Rough handling of equipment may cause dents and scratches which could have a local hardness exceeding Rc22, even if the base material is under Rc22. These dents have often been the cause of failures and consequently careful handling of tubing of tubing tongs is of vital importance.

For combating sour corrosion the use of an inhibitor may lead to risk since the smallest flaw may lead directly to a crack/destruction. Selection of suitable materials, although possibly costly, is the best defence against this type of corrosion. Acceptable materials for H2S service are specified in NACE Standard MR-01-75 (1978 revision). "Sulphide Stress" Cracking Resistant Metallic Material for Oil Field Equipment" (National Association of CorrosionEngineers). A broad outline of these material is given in the following sections.

6.3.1 Acceptable

1.API grade J55, K55, L80 and C75 material (preferably type 2) with a max. hardness of Rc22.

2.Low-alloy steels with a max. hardness of Rc22.

3.300 series stainless steels, in annealed condition. Max. hardness Rc 22.

4.K-Monel, hot rolled and age-hardened. Max. hardness Rc35.

5.Inconel and InconelX, max. hardness Rc35.

6.Hard-facing with stellites, colmonoy and tungsten carbide. Base material, max. hardness Rc22.

7.9% Cr -1% Mo steels quenched and tempered with a max. hardness Rc22.

8.Carpenter A-286 steel with a max. hardness Rc35.

9.Hastelloy B and Hastelloy C.

6.3.2 Not acceptable

1.Steels with a nickel content of more than 1%

2.Series 400 stainless steels

3.Precipitation hardened steels

4.Cold worked steels (below 1000°F)

5.Copper, copper alloys

6.Free machining steels (containing sulphur and lead)

7.High-strength steels

6.4 Low temperature service

For selection of materials and fabrication requirements not only corrosion but also the design temperature of production test equipment, including piping and accessories must be taken into account. In particular during a production test of a gas well the operating temperature can drop due to gas expansion. For temperature conditions as low as -20°F, sour service surface equipment is readily available from production test contractors and suitable for most exploration well testing conditions. However, if "low temperature source service" equipment is considered necessary below -20°F, then equipment should be specified to be suitable for low temperature -25°F (or lower). This design temperature was set at -25°F as at this design temperature impact testing is mandatory in accordance with the ASME code VIII division 1. Also stress relieving is mandatory at design temperatures below -20°F.

Materials, piping and accessories for low temperature sour service have to be suitable for operation at the minimum temperature and at the maximum allowable working pressures. As this low temperature sour service equipment is rented from service companies the Group company supervisor must ensure that adequate proof is handed to him by the service company concerning the acceptability of the test equipment.

6.4.1 Materials and fabrication standards for low temperature sour service

The following materials and fabrication standards have been set in order to safeguard well testing operations:

1.Vessels and piping shall be manufactured in accordance with ASME code VIII division 1.

2.All vessels and piping welds shall be 100% X-rayed.

3.All welds to be made under pre-heat condition of 212 degrees Fahrenheit with low hydrogen electrodes; permanent backing rings shall not be used.

4.All welds are to be stress relieved, maximum hardness Rc22 after stress relieving. Inspector selected welds are to be checked with a portable Vickers or Rockwell tester. (Stress relieving has been introduced in these requirements to ensure that fully ductile welds and heat affected zones will be present). Unfavourable material conditions could be present in view of high carbon contents of many American standard materials. Pre-heating, low hydrogen electrodes and stress relieving are introduced to prevent specifying low carbon content materials, which are generally not available in the USA.

5.Separators, including connections and piping, should be designed for low temperature service. The design temperature to be -25°F, unless otherwise specified at a lower temperature.

6.For low temperature sour service all accessories (valves, etc.) shall comply with appropriate NACE specifications. (Certain refinements taken up in the Company Sour service specifications are valuable, however, in order to simplify NACE specifications are accepted together with stress relieving and design temperature of -25°F).

7.Inspection reports from independent inspectors should be made available to the operating company renting the production test equipment. The Group operating company should also be provided with relevant data sheets, material specifications and certification of chemical composition and physical properties including hardness and Charpy impact values. Group company supervisors should scrutinise this data and make sure that the following pertinent information concerning rented test equipment is available, prior to production testing:

a)Evidence that materials used in fabrication of low temperature production test equipment, where applicable, are suitable for -25°F.

b)Proof that welding has been 100% X-rayed and is accepted by an independent inspector.

c)Proof on stress relieving of welds and hardness check by an independent inspector.

Production test equipment is to be rejected if (1), (2) and (3) do not conform with requirements.

Should standard surface equipment/materials downstream of the X-mas tree master valve be in use by a group company, and early detection indicates the presence of H2S, production testing is not to continue and the well must be killed.

Complete specifications for sour service test equipment, suitable for low temperature service is given in Section 12 of this report.

1 General

Successful production testing of exploration wells requires the choice of appropriate test string design, equipment and facilities, and strict adherence to safety measures. An integrated planning approach must involve production technology, reservoir engineering, production operations and drilling engineering. Setting clear test objectives which are fully understood by company and contractor personnel is essential.

There is currently renewed interest in the drilling of deep, high temperature and high pressure wells. During a test of this nature, surface pressures may approach 15,000 psi and temperatures of 300°F may be present with concentrations of H2S and CO2 (Partial pressures greater than 0.0142 psi and 7 psi respectively).

To achieve this, equipment exists or is being developed, that encompasses the following areas:

·Drill Stem Test Tools (15,000 psi @ 400°F)

·Subsea Tree and related equipment (15,000 psi @ 300°F)

·High Pressure surface equipment (15,000 psi @ 260°F)

·Surface Data Acquisition System

·High Temperature Memory and Amerada Equipment gauges

All equipment described in the following text has a 10,000 psi WP. For pressures up to 15,000 psi, special mention is made as and where necessary.

Typically, the main differences between 10 K and 15 K testing is in the equipment used upstream of the choke manifold. It is important to note that limitations imposed by high temperature may outweigh those of pressure on surface equipment. Temperatures below 175°F downstream of the chokemanifold,can also cause problems with relation to H2Sembrittlement(22 HRC). These issues are explained further in the guideline.

2 Summary of main changes resulting from high pressure/ temperature testing

Since HP/HT well testing is a non-routine activity it requires special attention in terms of

1.selectionof equipment,

2.programmingand preparation and,

3.supervision.

The following guidelines relate to 15,000 psi WP, 250°F temperature rating and H2S service. Where the temperature exceeds 250°F, special recommendations are made.

2.1 Equipment issues

2.1.1 Choice of seals

Tubing and accessories or DST string connections, should preferably have metal-to-metal sealing. If temperatures greater than 250°F and/or CO2 is envisaged, andelastomersare required to be used they are to be ofViton-type material, or equivalent, rated to 400°F.

2.1.2 Subsea

The subsea test tree (SSTT) should have a chemical injection point between the shear and block balls, and include a built in temperature transducer. This will facilitate guarding against hydrate formation, by the injection of chemicals and will also permit the monitoring of wellhead temperatures. The inlet connections at the SSTT should have integrated double check valves, and fittings should be of the autoclave type. Preference should be given toSSTT's,and Lubricators/Retainers valves, that use metal-to-metal seals due to potential gas impregnation and explosive decompression ofelastomerseals.

2.1.3 Surface Test Tree STT (Flowhead) and choke manifold

Surface test tree (flowhead), should have metal-to-metal seals as well as self-sealing metal-to-metal gate valves.

Chemical injection points at the STT,FlowlineManifold (or Data Header) and Choke Manifold, should have dual check valves incorporated and block and bleed facilities.Fittings to be of the autoclave variety.

All connections between the STT and the choke manifold should haveGraylocconnections and be of anchored rigid piping. Where movement between the STT and choke manifold is expected, (e.g. floating rigs), then aCoflexiphose withGraylocfittings is recommended. For flowing well temperatures in excess of 220°F continuous use ofCoflexiphoses is not recommended. Methods of lowering FTHT should instead be undertaken. These could include cooling of riser and/or choking back on well, at choke manifold.

2.1.4 Surface equipment downstream of choke manifold

Allpipeworkbetween choke manifold and inlet to steam heat exchanger should be rigid and straight. Where elbow sections are required these should have welded connections and where movement is expected, metal-to-metal seals are preferred. All the foregoing must be of 10,000 psi rating.

The steam heat exchanger rating should be 10,000 psi upstream of thechoke,and 5,000 psi downstream with a quick acting ESD system, activated by a high pressure pilot (PSH). This signal from the pilot would activate the SDV, located upstream of the choke manifold as well as vent trapped pressure to flare.

The temperature of the steam entering the exchanger will be controlled by a thermocouple device linked to a control valve. The steam lines will be fitted with non-return valves.

The 1440 psi standard separator should be fitted with audible alarms on both high and low levels, to assist in exercising immediate local control.

The surge vessel should have a vent line, sized large enough to cater for total gas flow via the liquid outlet of the separator, a situation that could arise in high rate condensate wells.

2.1.5Downholedata acquisition equipment

Care must be taken in the selection of memory gauges, as their temperature rating is restricted to ±350°F. Battery packs and clocks require specific attention, as they are particularly susceptible to damage resulting from very high temperatures. The possible H2S/CO2 effects at elevated temperatures should be carefully discussed with the gauge supplier. Use of elastomeric seals should be avoided for reasons discussed earlier. Service agreements that hold theOpcoliable for damage when operating within the pressure/temperature range specified, should also be avoided.

Downholeand wellhead samplers chosen should be mercury-free, due to potential hazards with this substance.

2.2 Supervision and quality control issues

·To achieve a safe and efficient operation, the following support functions are particularly important in high pressure and temperature applications:

·Quality Assurance and Control, Maintenance, Certification, Pressure Testing and Leak Detection and First Class Supervision. Deficiency in any one area may lead to an inefficient and unsafe operation.

·It is equally important to design wells such that well closure is possible AT ANY TIME.

·Each test should be treated individually, and all equipment should be tested to maximum operating or design specifications by:

-manufacturer

-certifying agency

-user

Additionally, records of field use, maintenance, inspection and certification should be available and reviewed.

It is the Company's policy to conduct their activities in such a way as to take foremost account of the health and safety of their employees and of other persons, and to give proper regard to the conservation of the environment. In implementing this policy Company not only comply with the requirements of the relevant legislation but promote in an appropriate manner measures for the protection of health, safety and the environment for all who may be affected directly or indirectly by their activities.

In following this policy they:

1.Recognise the importance of the on-going involvement and commitment of management and other employees and the necessity of ensuring that they have the required skills and support;

2.Seek to conduct all their activities in such a way as to avoid harm to the health of, or injury to, employees and others and damage to property;

3.Work on the principle that all injuries should be prevented, and promote actively amongst all those associated with their activities the high standards of safety consciousness and discipline that this principle demands;

4.Use their best endeavours to provide products, together with practical advice on their application, which will not cause injury to health or undue impact on the environment when they are used in accordance with this advice;

5.Apply the best practicable means to preserve air, water, soil and plant and animal life from adverse effects on their operations and to minimise any nuisance that may arise;

6.Use their best endeavours to ensure that contractors working on their behalf apply health, safety and environmental standards fully compatible with their own;

7.Keep their employees, contractors, and the relevant authorities appropriately informed of known potential hazards that might affect them; and make them aware of what is being done to minimise the risk and to improve the quality and safety of the working environment;

8.Establish and maintain contingency procedures to minimise harm from accidents that may nevertheless occur, and work with the relevant authorities and emergency services in an appropriate manner in the development and application of these contingency procedures;

9.Include an assessment of health, safety and environmental matters in the factors to be taken into consideration before entering into new ventures or activities or acquiring companies;

10.Work with governments, local authorities, industry, academic and professional bodies and employees or their representatives as appropriate and take the initiative, where necessary, to promote workable and improved codes of practice and timely and practical regulations which relate to the above matters;

11.Conduct or support research directed towards the improvement of safety and health at work, towards ensuring the safety of their products and towards the conservation of the environment;

12.Facilitate the transfer to others, freely or on a commercial basis, of know-how developed in these fields;

13.Include expected future requirements and anticipated developments in all the above areas in their long-term planning.

1 Bottom hole pressure and temperature

It should be noted that the information given in the following tables only partially shows the expected performance specification of the gauges. Company experiences in the 10,000 psi and 15,000 psi ranges are limited, thus no specific recommendation can be made here.

One of the problems associated with the compilation of such broad spectrum data sheets is the basis on which gauge specifications are quoted by the various manufacturers and service companies.

There are now many pressure and temperature downhole sensing devices, it is often difficult to ascertain just what each supplier means by their performance figures, how they define certain key functions and how this relates practically to field operations.

Two examples illustrate this problem:

·Many electronic gauges are used with a downhole memory recorder. The way that the memory records data can mask the performance of the sensing device.

·Specifications can often be misleading when quoted out of context. A "quartz" transducer displays impressive accuracy/resolution, until we take account of the poor real time thermal response of Quartz.

A "Quartz capacitance" gauge is sometimes thought to be similar to a "quartz" gauge, when in reality, the "quartz" component has to do with obtaining a smoother surface between capacitance plates and nothing to do with the way a vibrating quartz transducer operates.

In general, three main types of gauges are categorised as follows:

1.Bottom hole mechanical downhole recording pressure gauges.

2.Bottom hole electronic downhole recording pressure gauges.

3.Bottom hole electronic surface recording pressure gauges.

Manufacturers of pressure sensors most commonly depict their products and their performance characteristics through technical specifications. The definitions of the parameters describing the transducer performances are reviewed below.

Typical pressure measurement parameters can be split into the following two main classes:

·Static parameters

·Dynamic parameters

1.1 Static parameters

These parameters describe the transducer performances in static conditions. Under this classification, we find:

·Accuracy

·Resolution

·Stability

·Sensitivity

1.1.1 Accuracy

The manufacturer generally refers to the static accuracy which can be considered to be the algebraic sum of all the errors influencing the pressure measurement.

These errors are due to:

·MQD (Mean Quadratic Deviation): the discrepancy between the theoretical mathematical curve and the actual transducer response after calibration.

·Hysteresis: highest discrepancy of the transducer output signal between increasing and decreasing pressure excursions, at the same pressure level.

·Repeatability: the discrepancy between two consecutive measurements at a given pressure.

·dP/dT: temperature sensitivity of the pressure sensor.

1.1.2 Resolution

This is the minimum pressure change that is detected by the sensor.

When referring to a gauge resolution the associated electronics must be taken into account and one must specify the resolution for a certain sampling time (varies from 0.1 sec. to several secs.)

The gauge resolution (tool) is equal to the sum of three factors, the sensor resolution, the digitiser resolution and the electronics noise induced by the amplification chain. In the case of tools equipped with strain gauge transducers this latest factor is by an order of magnitude the predominant parameter.

1.1.3 Stability

This is the ability of a sensor to retain its performance characteristics for a relatively long period of time.

The stability gives the sensor mean drift in psi per day obtained at given pressure and temperature. Three levels of stability can be defined:

·short-term stability for the first day of test

·medium term stability for the following six days

·long-term stability for a minimum of one month.

1.1.4 Sensitivity

This is the ratio of the transducer output variation induced by a change of pressure to this change of pressure. In other terms, the sensitivity represents the slope of the transducer output versus the pressure curve.

1.2 Dynamic parameters

These parameters describe the transducer performances in Dynamic conditions. Under this classification we find:

·transient response during temperature variation

·transient response during pressure variation.

1.2.1 Transient response during temperature variation

The sensor response is monitored under Dynamic temperature conditions whilst the applied pressure is kept constant.

The peak error represents the maximum discrepancy between the applied pressure and the stabilised sensor output.

The stabilisation time represents the time needed to be within 1 psi of the stabilised pressure.

The offset represents the difference between the initial and the final pressure. This parameter provides for a given temperature variation the time interval required to get a reliable pressure measurement.

1.2.2 Transient response during pressure variation

The sensor response is recorded before and after a pressure variation whilst the temperature is kept constant. Peak error and stabilisation time are measured as previously described.

1.3 Bottom hole mechanical downhole recording pressure gauges

These self-contained gauges are the type most commonly used in the petroleum industry, especially during exploration well testing operations, where the BHT is below 350°F. Approaching this temperature it is normal to run electronic gauges possibly with mechanical gauges as a back -up provided the 350°F is not surpassed.

In HPHT testing operations above 350°F, it is normal to run gauges in bundle carriers as part of the completion string as this gives the best chance of recovering pressure and temperature data. Additionally, this obviates wireline runs.

They comprise the following three essential components:

1.A pressure/temperature sensing device (e.g. a Bourdon tube).

2.A pressure-recorder section.

3.A mechanical clock.

This type of recorder is field proven and reliable. Normally two pressure recorders and one temperature recorder are run on wireline. The recorders are "hung-off" in a landing nipple with a soft setting tool and the wireline removed from the well. At the end of the test the recorders are retrieved again by wireline. The recorder chart can be read with the aid of a chart scanner which takes up to two hours per chart. Instead of a temperature recorder a maximum thermometer is often run in the nose of the lower pressure recorder. If bottom hole temperatures are expected to be above 300°F special high temperature clock and elements (non-bellows type) have to be used.

The handling of the pressure recorders is not only critical in the well during flow periods, but also during rigging up and running of the recorders. On occasions the readings on the chart have been completely obliterated by bouncing of the stylus. Correct handling, careful running and proper locking in place of the recorder in the well minimizes jarring of the stylus to provide readable charts.

If the pressure element has not had recent use (e.g. for two days) it should be reactivated by pre-pressurising and checked prior to a survey. Pre-pressurising consists of applying approximately the full range pressure, two or three times, in a short time period (e.g. 2 to 3 minutes). This is performed using a hand-operated pump, a calibration adaptor and a conventional dial gauge. Since the Bourdon tubes in all pressure elements "relax" when not in use, they are always pre-pressured at the factory before being calibrated to generate the calibration data.

1.4 Bottomhole electronic downhole recording pressure gauges

Recorders of this type are self-contained battery operated devices. The recorders are run on wireline and "hung-off" in a similar way to mechanical recorders. In most of these gauges a transducer converts force or displacement into an electrical signal that is recorded downhole. Pressure and temperature are recorded when the gauge is returned to the surface.

1.5 Bottomhole electronic surface recording pressure gauges

Gauges of this type incorporate a means of measuring bottom hole pressure and temperature and a method for transmission of measurements to the surface for recording as a function of time. Most of these gauges have a single conductor armoured cable to transmit the signals from the sensor to a monitoring system at the surface. The main advantages of this type of gauge are as follows:

1.During the test, malfunction of the gauge is immediately apparent and remedial action can be taken.

2.Pressure data can be interpreted instantly and the length of the various test periods adjusted accordingly.

These advantages can save costly rig time; gauges of this type are summarized in Table 300.

Whilst the conventional bottomhole mechanical downhole - recording pressure gauges technology has basically remained static, various manufacturers have entered the electronic gauge market and a thorough survey is recommended, prior to selection. Additionally, with very high pressures and temperatures, there is only a limited number of manufacturers that offer gauges above 300°F.

2 Surface pressure and temperature

Surface Data Acquisition using transducers processors and computer operated reporting systems have developed rapidly over recent years. They are now considered to be reliable, cost effective and common place, particularly in High Pressure/High Temperature well tests.

As monitoring of essential parameters become automated and real time, such a system would have the added value of identifying problem areas before equipment failure occurs.

2.1 Tubing head

The tubing head pressure and temperature are taken at the flowline manifold upstream of the choke manifold and are both recorded on a chart recorder. In addition, the tubing head pressure is measured at regular intervals by means of a deadweight tester. It should be noted that a deadweight tester does not give accurate readings on a floating rig due to heave; in this case electronic wellhead gauges can be used. Specifications of four types of these gauges are given in Table 301.

2.2 Separator

The separator temperature is measured by a thermometer placed in a thermowell in the outgoing gasline. The separator pressure is measured and recorded upstream of the orifice in the gas outlet line. The differential pressure over the orifice is measured by a meter (Barton) in inches of water.

2.3 Flowlines

It is recommended that pressure gauges are installed downstream of the control valves in the gas and oil line to the burner booms, so that the back pressure of the flares can easily be monitored.

2.4 Heater

When a heater is used there should be thermowells and pressure taps on inlet and outlet lines.

3 Flow rates

Flow rate figures are used as the basis of important decisions at a much later stage after the test. It is therefore very important that the flow rate figures are accurate and reliable. Reading of relative sections of EP-61-000, Planning and Programming Manual, addresses the following topics more definitively.

3.1 Liquid flow rates

Liquid flow rates are measured using positive displacement meters, turbine meters or vortex type meters which are positioned in the fluid outlet line of the separator. The readings of these meters are compared with measurements in a gauge tank at regular intervals during the test.

The meter readings are then multiplied by the meter factor to find the correct flowrate (It should be noted that the meter factor includes the correction for the shrinkage).

Liquid flow rates are reported at 60°F. For this purpose the meter reading is multiplied by a volume reduction factor "K". This factor is given in tables when the temperature and specific gravity of the fluid are known. Most separators have a shrinkage tester built on the same skid. This shrinkage tester can be used to estimate the shrinkage during the test. It should only be used for flow calculating purposes when there is no gauge tank available. It is recommended that the oil in the gauge tank is allowed to settle for about half an hour to allow gas to escape, and hence allow a more accurate figure to be obtained. A further advantage of a gauge tank is that it facilitates accurate BS and W measurements.

3.2 Gas flow rates

Gas flow rates are always measured with an orifice type meter. Before the test the differential pressure meter should be checked with a U-tube manometer and the static pressure recorder with a deadweight tester. Care should be taken that no liquids can accumulate in the lines from the orifice fitting to the meter. A layout with drip-pots in the lines to the meter is shown in Section 3.9.1. It should be appreciated that not all the gas is measured by the orifice meter in the gas outlet of the separator; there is still a certain amount of gas in solution in the oil leaving the separator; tables are available to calculate this amount of gas.

The production test contractor should have complete documentation material on site allowing calculations to be easily checked.

4 Specific gravities

The values of the specific gravity of oil and gas at 60°F are used to calculate the respective flow rates.

4.1 Specific gravity of oil

The specific gravity of oil is measured using a hydrometer according to ASTM D1298-67 IP 160/68 "Density, Specific Gravity or API Gravity of Crude Production and Liquid Petroleum Producers". A full set of hydrometers should be part of the production test laboratory equipment.

The sample for specific gravity measurement should contain no water; the specific gravity measurement is expressed at 60°F.

4.2 Specific gravity of gas

The specific gravity of a gas is measured with a gas gravitometer. This meter works on the principle that the torque produced by a wheel which is activated by a jet of gas is proportional to the specific weight of the gas. The difference in torque produced by air and the tested gas is shown on an indicator scaled to read in terms of specific gravity (the specific gravity of air is one).

5 Sampling

The sampling requirements are based on the principle "Sample while you can". Hence as many samples as necessary should be taken during a given formation test, because a second sampling opportunity may not arise. However, sampling is only effective if it is representative of a "turbulent" stream emphasising the "where" sampling point.

Sampling is inexpensive compared to testing; therefore if there is an opportunity to take improved quality samples of a previously sampled interval, these samples should be taken and the earlier samples discarded.

Water samples should never be stored in tin cans, but always in glass or plastic bottles and always filled completely to the top.

Aluminium or stainless steel containers should be used for PVT samples. For storage of oil samples, 600 cc stainless steel containers are normally used with a maximum working pressure of 1800 psi; for storage of gas samples 20 litre aluminium containers are used with a maximum working pressure of 2800 psi. Shipping containers for bottom hole samples must have a maximum working pressure of 5,000 psi, 10,000 psi or 15,000 psi.

All sample containers should be provided with a firmly attached clearly legible identification enclosed in a weather-proof envelope. Sample bottles should always be shipped in special containers or crates.

The samples to be collected during a production test of an exploration well can be classified as follows:

1.Crude oil/condensate samples

2.Water samples

3.Gas samples

4.Surface PVT samples.

The quantity of samples collected should be a multiple of that required for analysis (as stated in Guidelines for manual sampling and analysis of hydrocarbon fluids) for the following reasons:

1.Loss/damage of samples during transportation.

2.Interest of third parties (associates, offtake refineries)

3.Repeat analysis in laboratories.

4.Interest of MF and EP functions in small samples.

5.Interest of MF and EP functions in drum samples for future field development.

A typical set of samples would be 10 pcs 200 litre drums for crude oil/condensate, 10 pcs 5 litre cans for crude oil condensate and 3 pcs 20 litre sampling bottles for gas produced from each separation stage.

5.1 PVT samples

Oil and gas PVT samples, taken from the separator at surface, are later mixed in the laboratory in the ratio according to the (Gas-Oil Ratio) GOR measured at the time of sampling, in order to acquire a representative sample of the original composition. Due to possible inaccuracies in gauging the oil flow rate and the gas flow rate the GOR may not be accurate and have an adverse effect on the composition of the mixture. Therefore bottom hole PVT sampling is preferred for oil wells.

The special bottom hole PVT sampling equipment, containers and services are available from service companies as follows:

1.Schlumberger - using surface controlled opening and closing of the sampler mechanism run on electric cable.

2.Schlumberger, Ruska, Woffard and Leutert - using (downhole) clock-controlled opening and closing of a sampler mechanism run on wireline.

Bottom hole samplers run on wireline are complicated in design since they include a clock mechanism. Bottom hole sampling requires experienced and skilled personnel, which is certainly the case with samplers run on wireline. A higher success ratio has been obtained with a sampler run on electrical cable which does not require a clock to activate its tripping mechanism.

Although the rental rate of electrically operated samplers is higher than the rate for wireline samplers, the total time involved to obtain representative bottom hole samples is generally less and therefore makes its use preferable on high rental (offshore) rigs. On retrieving PVT bottom hole samplers from oil wells, the bottom hole pressure will cause sufficient differential pressure for sealing off the trapped sample. This may not occur in the light gradient gas/gascondensate wells, since the trapped sample also loses temperature and therefore pressure, and sealing of the trapped sample becomes difficult. For wells with a GOR in excess of 2000, bottom hole sampling becomes unreliable. It is therefore recommended that surface PVT samples are obtained of large enough volumes for high GOR wells.

Enough bottom hole samplers should be available during a production test; one is used for transferring the bottom hole sample into the appropriate shipping container, while others are being run downhole to take a sample. The samples should be taken in accordance with API publication RP-44 ("Recommended Practices for Sampling Petroleum Reservoir Fluids"). It is recommended that 3 bottom hole PVT samples are taken preferably after the main build-up period, at a low flow rate (the flow rate should be high enough to obtain stable vertical flow conditions).

5.2 Sampling of gas for H2S analysis

Sampling cylinders made of low hardness mild steel, stainless steel, aluminium alloy or glass are safe for use with sour gas but not suitable for collection of gas for H2S analysis. The H2S will react with the sampling cylinder material and may be partly or completely absorbed in a short time. Internal coating of sample cylinders does not give satisfactory protection against absorption of H2S; the analysis is therefore performed on site (Section 11). The analysis can be carried out by the mudlogging contractor making use of electronic instruments, or by the production test contractor making use of Drager tubes. Equipment used by the mudlogging contractor should be checked and calibrated prior to production testing.

5.3 Natural gas sampling

Portable test equipment is available for use on-site to carry out flash separations, and measure and sample the resulting liquid and gas streams over a range of pre-selected pressures and temperatures. A typical use of the equipment is during the appraisal period of a new gas or gas-condensate field, to simulate likely process and handling conditions and forecast liquid yields and lean-gas properties over a range of conditions. This provides a more reliable basis for the design of facilities than could be obtained using normal calculations.

5.4 Trace elements

Services are available to sample gas during a production test and determine on site small quantities of the so called "trace elements" as well as very small quantities of H2S.

6 Sand

It is sometimes expected that a well will produce sand on a continuous basis, after "cleaning-up" (this is based on logs and cores). Sand production in oil and gas wells will later cause serious erosion in permanent production facilities. It is therefore most important to estimate the sand production rate at an early stage and establish which section of the producing interval produces the sand. This allows remedial action, such as gravel packing, sand consolidation, or plant design changes to be planned. The sand production rate of oil wells is measured by taking frequent well head samples which are centrifuged. When the sand production rate is low a large well head sample is taken and screened using a sieve, the sand production rate is expressed in lbs/1000 bbl. The sand production rate of gas wells is measured using a sand filter. At the end of a certain flow period the filter is opened up and the sand is weighed. The sand filter should be positioned upstream of the choke and have a by-pass incorporated.

7 Viscosity

The reader is referred to standard test method ASTM D445-79 - "Kinematic Viscosity of Transparent and Opaque Liquids (and the Calculation of Dynamic Viscosity)".

7.1 Kinematic viscosity

The kinematic viscosity is determined by measuring the time for a volume of liquid to flow, under gravity, through a calibrated glass capillary viscometer. The viscosity varies with temperature and therefore the viscosity is expressed at a certain temperature.

7.2 Dynamic viscosity

The Dynamic viscosity can be obtained by multiplying the kinematic viscosity by the density of the liquid.

8 Pour point

The reader is referred to standard test method ASTM D97-66 - "Pourpoints of Petroleum Oils".

The pour point of an oil is defined as the lowest temperature, expressed as a multiple of 3°C (5°F), at which the oil is observed to flow, when cooled and examined under prescribed conditions.

Pour points must be determined on clean oil samples by an experienced operator, in the laboratory, using the correct equipment. Simplified procedures carried out in the field may produce misleading results.

If in doubt, seek specialist advice.

9 Cloud point

The reader is referred to standard test method ASTM 250081-"Cloud point of Petroleum Oils".

The cloud point is defined as that temperature, expressed as a multiple of 1°C (2°F) at which a cloud or haze of wax crystals appears at the bottom of the test jar when the oil is cooled under prescribed conditions.

In opaque oils, the crystallisation point of wax is determined by observation of the temperature drop of a cooling sample as a function of time. A sudden decrease in the cooling rate is caused by heat released by crystallizing of the wax. Cloud points must be determined on clean samples by an experienced operator, using the correct equipment.

9.1 Flow, temperature and pressure monitoring points

9.1.1 Transducers

The schedule of transducers normally used are as follows:

ParameterRangeAccuracy % (PSD)

Temperature0-300°F0.25

Pressure0-1,000 psi0.1

0-1,500 psi0.1

0-5,000 psi0.1

0-10,000 psi0.1

0-15,000 psi0.1

Differential pressure0-200 ins/wg0.25

0-40 ins/wg0.25

0-400 ins/wg0.25

Flowrate0-10000 bbls/d0.01 bbl/resolution

These are the main ranges of transducers.

9.1.2 Data requirements

In brief the requirement for surface data is as follows:

1.Subsea tree (LRT)

temperature

2.Swivel (URT)

temperature

a)Wellhead

-pressure

-pressure

b)Choke manifold (downstream)

-pressure

-temperature

c)Separator

-gas line pressure

-gas line temperature

-orifice differential

-pressure

-oil temperature

-oil flow rate

-water flow rate

1 Surface

1.1 Anti-pollution measures

It is possible that hydrocarbon pollution of surface waters could occur during production testing. A spill is likely to be limited as the well and production test equipment are constantly monitored and rigged to enable instant closure of the well. Anti-pollution equipment and materials to handle oil pollution must, however, be readily available during well testing operations.

Disposing of crude oil through burners may cause pollution. This is not always detectable at the offshore location (strong currents, adverse weather conditions). Helicopters are usually available in an area where well testing occurs and should be used during routine or special flights, to survey the area around the rig where well testing is in progress, to detect possible spillages.

Although the best way to counteract oil pollution is physical removal of the crude, a practical alternative is the use of low toxic detergents. These dispersants work by changing the interfacial properties of oil and water so that mild agitation will break up the oil layer into very small droplets which will be dispersed in the upper layers of the sea where natural processes such as evaporation, dissolution and biodegradation remove much of the oil. Supply/Standby boats should have a quantity of this material and spraying equipment on board during well testing.

1.2 Disposal of hydrocarbons

The pilot flame on the crude oil burner is normally supplied with bottled propane gas, purchased locally.

When the rig has no sprinkler system or the system is inadequate, it is advisable to arrange for fire hoses to keep equipment and hull wet in the vicinity of the flame.

The waterlines to the burners should be flushed before the test, with the spray nozzles at the burner removed, so that rust particles will be removed.

It is good practice to test both burners, by pumping and burning diesel oil, before the actual production test starts. For smokeless burning, water should be injected into the flame at an oil/water ratio of 1:1.2.

1.3 Hydrate prevention/antifoam injection

In the presence of free liquid water, hydrocarbon gases and natural gas components can form a solid snowlike substance called "hydrates". Methane, ethane and propane readily form hydrates, butanes less readily.

Pentanes and heavier hydrocarbons do not form hydrates and tend to inhibit hydrate formation in the other compounds mentioned.

The formation of hydrates will occur in the presence of free water under specified pressures and temperatures. In general, the lower the temperature and higher the pressure the more readily they are formed, but water in the vapour phase does not form hydrates.

Hydrates may accumulate in the flow system where the gas flow changes direction/velocity, e.g. in bends, valves, reducers, thereby rendering valves inoperable and blocking the gasflow.

The conditions for hydrate formation, temperature and pressure of the gas flow, may be estimated using the gas analysis and hydrate prediction curves, which are based on vapour solid equilibrium constants. More rigorous calculation methods can be found in the NGPSA Manual or in computer programmes.

Where cooling of the gasflow occurs there is also a possibility of hydrate formation, e.g. a pressure drop over a choke or other restriction causes a temperature drop; this can also occur in a transport line or any other point of the gas handling system.

The presence of non-hydrocarbons in natural gas may have an effect on hydrate formation. N 2 has hardly any effect, CO 2 has a pronounced effect in the formation of hydrates.

Hydrate formation can be suppressed by adding freezing point suppressants to the free water containing gas flow. The most convenient soluble material used for this purpose, when production testing exploration wells, is methanol. Glycol can also be used, but in the presence of H2S methanol is preferred as glycol forms a highly corrosive sludge in combination with the gas. Both fluids are flammable, especially methanol, and should be treated with care, avoiding contact with the eyes.

Natural gas is usually assumed to be saturated with water vapour (i.e. in equilibrium with free water) at bottomhole temperature and pressure. Any free liquid water that is produced with the natural gas, in addition to the liquid water that separates due to changes in temperature and pressure, will also require hydrate suppression. For production operations it is assumed initially that the well does not produce free water.

To prevent hydrates forming, after the choke, heat the gas immediately after the choke so that any formed hydrates are melted. When a heater is not available, methanol should be injected before the choke. On floating rigs it is advisable to inject methanol at seabed level to protect the tubing riser from hydrate formation.

1.3.2 Antifoam injection

Antifoam chemicals eliminate foam in gas-oil separators, thus preventing oil carryover and increasing the throughput. High viscosity Dow Corning 200 fluids are recommended, diluted in either white spirit or diesel oil, and applied ahead of the gas-oil separators, for more efficient dispersion and metering. It is recommended that Dow corning 200/12,500 Cst is available during production testing. The addition of minute quantities (0.001 - 0.025ppm) of anti-foam agent in the separation inlet lines has resulted in 40% increases in throughput.

The recommended quantity required for successful treatment during well testing is 0.01ppm.

1.4 Guidelines for opening up a well

The following guidelines should be observed (see well programme for details):

1.Never open up a new zone during the hours of darkness.

2.Inform the company toolpusher of the plans.

3.Check lines to burner are open and pilot flame on.

4.Ensure that safety shut-in system is operable.

5.Open up the well on a 16/64 adjustable choke. Observe the well for a reasonable time. Do not bean up too quickly.

6.As soon as the first well effluent appears at the surface, a check should be made for H2S. H2S is a colourless and transparent gas and is flammable. It is heavier than air and may accumulate in low places. When H2S is present special alarm and safety precautions have to be taken and all operations such as sampling, blowing down pressures etc. should be carried out according to special instructions and procedures.

A concentration in the air of 100ppm H2S deadens the sense of smell in 3 to 15 minutes and a concentration of 500 ppm kills a person in a few minutes.

7.Sometimes the well will unload very slowly. In order to gauge low rates, the time to fill a bucket is measured. A record of the filling time will give an indication of the well behaviour and the total volume produced. This unloading can take a very long time (10 hours is not exceptional).

8.Try to avoid producing the well direct into the gauge tank. The danger is that gas might break through suddenly and because the flame arrester on the gas vent of the tank cannot handle large volumes of gas, the pressure in the tank will build up and may cause the tank to burst. (A few inches of water column pressure is sufficient to blow the roof off of a square shaped gauge tank).

9.Bypass the separator until clean fluid is being produced. However, keep a good record of bean size and production time so that the quantity of oil produced, during separator by-passing, can be calculated later. Take samples for BS&W determination at the flowline manifold upstream of the choke or at the Xmas tree.

1.5 Bringing in marginal wells - jet pumping, coiled tubing, etc.

It is possible that marginal wells will not come in, even by circulating the tubing contents to diesel oil. Various methods are available such as swabbing, jet-pumping, gas bombs, coiled tubing etc. Due to the temporary nature of the facilities for a test set-up, it is not normal to utilise swabbing and gas bombs either due to their hazardous nature or their ineffectiveness. Jet pumping has been used with success, but is dependent on supply of adequate quality power water etc. As a coiled tubing unit is nowadays reasonably inexpensive and usually already on site for other operations, e.g. acidising, this can effectively be used to bring in the well and is the preferred route.

2 Subsurface

2.1 Wireline operations

1.Slickline wireline operations can best be carried out with either the wireline unit positioned on the drill floor or on the catwalk. When positioned on the drill floor, it provides easier access to the well and simplifies communication between wireline operator and assistant. However, the following factors must be considered.

a)There should be ample space on the drill floor so that the unit can safely remain in place throughout the duration of the test.

b)The unit must have an air or handstarter, spark arrester and rig saver device, i.e. certified for zone 1/2 operations.

In all other situations, the wireline unit should be installed on or next to the catwalk. Walkie-talkies should be used for communication.

2.Wireline unit speed should be 2800-3000 ft/min with a full drum to ensure effective jar-up action in deep deviated wells.

3.Though many operations can be performed with the wireline system, it is essential to keep the number of wireline runs down to a minimum during production testing in order to minimise the chance of problems during wireline operations.

4.It is generally not advantageous to leave wireline in the well during bottom hole pressure surveys. Where possible, permanent pressure and temperature monitoring equipment with a surface read-out should be designed into the completion string. If it is necessary to run and set subsurface recorders, soft release running tools and instrument hangers with appropriate locks have been used successfully.

5.Pulling a set of recorders from the derrick floor or spider deck into the lubricator requires extreme care. If the dogs of the instrument hanger inadvertently catch behind some obstruction during handling, the pressure recorders will be released and may cause injuries to personnel and/or fall through the spider deck.

6.When gradient surveys are necessary, it is advisable to use inhibitor on the wireline. Inhibitor can be applied by injection into an injection sub fitted in the lubricator. Flowing bottomhole pressure surveys have been made with the wireline in the hole using sufficient weight, e.g. lead filled stems, to keep the instruments down against the well flow. Decrease of weight, shown by the wireline weight indicator, is a doubtful check on whether sufficient weight is applied. Observed weight loss implies that the pressure recorder may not be recording at the planned depth but higher up, or worse that the wireline may have been partly blown up, looped or even broken.

7.It is common practice to run wireline through open surface controlled tubing retrieval subsurface safety valves; however, care must be taken to ensure that the control pressure is some 1500psi higher than the closed-in tubing head pressure to keep the SSSV open.

8.All components of the toolstring, stems, jars, wireline head etc., must have fishing necks, so that a disconnected string can easily be fished by wireline methods.

9.After make-up V-packing (used on test plugs, subsurface safety valves, etc.) should have a diameter slightly less than that in which it is to pack-off. Pressure over the V-packing will expand it and ensure tight pack-off. V-packing material (e.g. Teflon, Viton) should be resistant to the influence of CO2, H2S, etc. to avoid swelling/destruction.

10.O-rings, and back-up rings used in conjunction with O-rings, must also be resistant to CO2, H2S, etc. to avoid disintegration. Special elastomers are required when the temperature will be above 250-300°F (K-Ryte).

11.No-go nipple and Test tool can be used for pressure testing of the tubing string; the wireline can be left attached to the test tool while pressure testing. Tubing pressure tests have been made with X-equipment; however, several cases of rupturing X-mandrels, while pressure testing at 2500-3000 psi, have been reported. Although the X-line is improved in this respect it is recommended to use the RN nipple and test tool.

12.In a newly completed well, it is good practice to run a tubing end locator to "tag" bottom and determine the location of the tubing shoe prior to routine wireline work.

13.It is good practice to cut the last 30-50 ft of wireline at the start of a new series of wireline jobs. The wireline operator must ensure that no one is in the path of the line when cutting it. The cut line will coil up quickly towards the wireline unit and could cause injury to any one in its path.

2.1.1 Logging during high flowrates (electric line)

When logging operations need to be carried out in high fluid velocity wells and it is necessary to leave the tool stationary in the well for extended periods of time, the following recommendations should be considered:

1.Position the tool, where feasible, below the bottom perforations.

2.If this cannot be achieved, position the tool above the top perforations but keep tools away from the tubing shoe in order to avoid possible turbulent areas.

3.Never leave the tool in front of the producing interval. It may permanently damage instruments such as gradiomanometer, flowmeter, etc.

4.It is possible to keep the toolstring under tension (and thus motionless) by making use of a tubing-end locator at the bottom of the toolstring. In this case, a perforated joint should be installed above the tool.

5.Do not close the BOP rams on the cable, otherwise the tension monitoring capability will be lost.

6.Keep the well shut in, when running-in, in order to avoid problems running through restricted sections.

7.Never enter the tubing shoe with the equipment when the well is flowing at high rates.

8.In order to minimise dyCompanyic effects and detrimental shock waves on tubing restrictions, open the well very slowly, by 200 to 500 bbls/day per 5 min for casings ranging from 41/2 in to 95/8 in. Special caution should be exercised when opening up oil wells with a gas cap.

9.Before pulling out, shut-in the well in order to enter the tubing shoe and pass the restrictions. If it is undesirable to shut-in the well, the production rate must be limited to a fluid velocity of less than 30 ft/s with the toolstring passing through the smallest restriction in the tubing string.

2.2 Tubing/connections

1.It is good practice to make a sketch of the tubing string composition showing inside diameters of all components. This will assist in determining limitations for wireline work and thus avoid embarrassing situations once the string has been run.

2.Prior to running the completion string, the components must be checked/tested at the surface by:

a)Drifting (to ensure sizes used are correct, no fabrication mistakes or damage have been incurred).

b)Pressure testing.

c)Simulation of downhole operations, e.g. open/close sliding side doors, operate subsurface safety valve, operate pinned components and redress them.

3.Tubing must be clean internally to make successful wireline work feasible. Air operated tubing cleaners or power brushes can be used for removing scale, dust etc. API modified thread compound should be applied sparingly, to pin ends only, while running the joints. Excessive use of pipe dope can permit it to build up inside the tubing which will severely hamper or even prevent wireline operations.

4.Tubing must be drifted or go-devilled and threads inspected to eliminate damaged joints incurred during transport or handling on previous jobs, e.g. by powertongs.

5.The torque used while making up tubing joints should be strictly controlled to prevent damaged joints and/or leaking connections.

6.The Completion string must be tested hydraulically. If the aforementioned precautions have been adhered to, it is usually superfluous to use inside - or outside - tubing testers (Hydrotest and Gator Hawk respectively).

7.It is normal practice to pressure test the tubing with a wireline plug set at the bottom of the completion string. This method has been successfully performed on many occasions.

a)All joints of the tubing string that are used for well testing must have thread-protectors fitted before/after use in the well. Supervisors should ensure that no thread-protectors are lost. An adequate number of spare thread protectors should be available with each tubing test string. DRILLTEC protectors are preferred.

b)When the tubing will not be used for a period of more than six months, it is recommended to protect the tubing by spraying internally with Shell Ensis 210 plus 25% Shell Cyclo Sol 51 and externally with Tretolite KP-94 Black material.

It is advisable to contract out tubing inspection and running services to the supplier of the pipe. Vallource , for example, have such a service and this strategy has shown an improvement in number of rejects and success rate.

2.3 Sliding side door

1.The sliding side door (SSD) positioning tool has spring-loaded dogs which locate in the sleeve to be shifted. The dogs, during running in/out, are in contact with the tubing wall and are exposed to excessive wear if the shifting tool and tubing are of the same nominal size. Shifting of the sleeve may then become difficult/impossible. It is preferable to incorporate a sliding side door, which is smaller in nominal diameter than the tubing string. Faster running/pulling of the shifting tool is then an additional advantage especially when wireline work has to be carried out in mud.

2.Prior to shifting, the pressure differential over the SSD should be reduced, if possible, to a minimum to facilitate smooth shifting, to avoid heavy jarry on the sleeve and prevent blowing up of tools.

3.Circulating velocities through the SSD should be restricted to 3 or 4 bbl/min to reduce the possibility of washing out the slots of the SSD.

4.Every SSD should be checked, for proper operation and inside diameter, on the surface prior to running the completion string. Particular attention should be given to used SSDs which should, in addition, be redressed/tested prior to running in with the completion string.

2.4 Completion fluids/mud

To promote trouble free wireline operations the well should be circulated to a clean fluid of low viscosity.

Brines are preferred because their densities can be adjusted within a wide range. For densities in excess of 1390 kg/m3, mixed brines containing bromides are required which are very expensive and must be handled and maintained with great care. In these cases, it is worthwhile to consider the use of powdered, preferably acid degradable, solid weighting material suspended in a viscous liquid. A stable fluid can be made in this manner provided it is properly formulated and prepared.

This cannot always be achieved in remote drilling locations and, therefore, reversion to completion in mud and minimum wireline operations should be considered. Accumulation of coarse suspended matter in completion fluids will jeopardise wireline operations and should be avoided by proper fluid handling - a high VISCOSITY can limit or even prevent jar action. In some cases, often due to cost and/or transport problems, an exploration well has to be completed in drilling mud. Wireline operations can be carried out under these circumstances, but take more time and are more difficult to perform (e.g. slow running in, reduced jar action, less response at surface).

It should also be realised that circulating/displacing drilling mud through a SSD needs higher pressures and so causes rapid cutting out of the circulating parts of the SSD.

2.5 Circulating/kill valve

If during tubing pulling operations, the well starts to flow or loss of liquid level occurs in the well, a circulating valve is immediately required. To cope with such situations, it is necessary to have a circulating/kill valve on the drill floor which can be screwed on the tubing immediately when flow or losses occur. The circulating valve should have a connection suitable for circulating purposes, e.g. 2 in. Weco Figure 1502.

2.6 Annulus operated valves

For reasons of simplicity, practicality and safety, these valves are used in the tubing string to allow activation of mechanical parts. This is accomplished by pressure pulses of varying intensity and duration. This is further discussed in Section 6.

2.7 Tubing string operated valves

Valves that are operated by tubing set, down weight and by picking up the string, are sometimes used in DSTs, e.g. Ful-FLO hydraulic circulating valve.

2.8 Packers

1.Check at an early stage that the packers are the correct size and that the bore is compatible with the seal assembly. Remove the flapper at the bottom of the packer if one is installed.

2.Ensure that the logging contractor has the correct adapter kits for setting the packer.

3.Permanent packers have been milled out and retrieved. Company has reported an average of 6hours required to mill/retrieve Baker Model D and DAB packers from about 9000 ft, on 21 jobs, with 100% success ratio.

2.9 Stabbing shoe

Several well test reports have mentioned damaged mule-shoes after stabbing the production string through the permanent packer, resulting in extra wireline work to swage open the mule shoe to make the passage of wireline tools/perforating guns possible. Damage can be avoided by using a barrel shaped stabbing shoe.

The testing contract strategy is an integral part of the project execution plan. The contract strategy needs to be finalised at the earliest opportunity, i.e. the planning stage. Well testing cannot be viewed in isolation from other facets of the drilling and production operations. The strategy adopted should take into account the other contracting strategies involved in operations. Since may of the major testing contractor form parts of large integrated service company groups there may be considerable benefits in combining testing contracts with for instance wireline logging/well evaluation contracts.

The contracts strategy should aim to:

·Reduce the number of contracts that the Company manages

·Simplify contract and testing operations management

·Provide contractor with incentives to perform

·Allow contractor reasonable control in the management of the execution phase

·Enable contractor's involvement in the planning of the execution phase

·Utilise the contractor's in-house expertise in well testing operations

1. Contract strategy

A Contract Strategy will address amongst other issues:

1.Plan of all contracts to execute the test

2.Commercial form

Turnkey

Unit rate (lumpsum elements)

Day-rate incentives/re-imbursable cost

3.Method of Contractor selection

4.Integration and interfacing of contractors

Factor affecting the contract strategy will include;

1.Local environment

Company contracting policies

Government requirements influencing contracting out work

2.Availability of equipment, suitable contractors and their respective capabilities to undertake either elements of or the total scope of work.

Award of the well testing contract(s) should preferably be made at well planning/design stage in order to allow the contractor's input into the final well programme.

Drilling unit selection will have a bearing on the well test equipment configurations possible. Layouts of equipment can affect the drilling unit's classifications, e.g. hard piping must be approved of by the drilling unit's certifying authority (DnV, ABS, etc.) layouts can also be affected by governmental regulations concerning interfaces of hazardous areas, etc.

Therefore drilling unit selection particularly for offshore units should take into account well testing plans and vice versa.

Advice on the local environment affect the planned contract strategy can be obtained from the Company Finance and Commercial Services departments.

2. Contract options

2.1 Contract each individual service

This should be avoided as much as possible. It is likely that any of the contractors will be able to, or be prepared to, price any of the work under any form other than a day-rate re-imbursable cost, since individual contractor performance will be so reliant on other contractor's performance over whom they have no control. Management of the execution of the test also becomes more difficult. Extra personnel will be required on site, each contractor having their own supervision.

2.2 Contract as a complete package

A fully integrated well test contract is usually the preferred option. The integrated contract is employed to manage the total project, from execution design through the recommendation and provision of all suitable equipment and services essential for the acquisition of high quality data to its final timely presentation. The contract should be constructed such that the contractor has an incentive as well as an obligation to provide suitable quality equipment and services for any particular test regardless of source. It should encourage the utilisation of new technology and techniques that will improve well test performance.

2.3 Contract as engineering and management

In areas where little in-house well test expertise is available or non-routine well tests are planned an engineering management type contract may be considered. The appointed contractor would be paid to put a job specific well test package together and manage its execution. From the basic specification of the deliverables specified by the operator, the contractor would refine the scope of work and subcontract all the required services and equipment.

Use of multiple sources for similar services, particularly when the Shell Company is the sole customer of the contractors will lead to unnecessary overhead costs to the Company due to low utilisation of each contractors facilities, etc.

When using an integrated contract type care should be taken to allow the lead contractor to create an integrated package which is not merely the sum of Company specified subcontractors. A sense of ownership and flexibility in choice has to be generated by the lead contractor to obtain the maximum benefit from an integrated contract.

3. Commercial form

When deciding on the commercial form particular attention needs to paid to how well the scope of work can be defined and the chances of having to change the scope of work after contract finalisation.

Any turnkey type contract should always include a set of unit rates that allows changes of the scope of work extending the flow period, extra data gathering, etc.

In general, turnkey type contracts will only be applicable for small well defined types of testing work.

The form should allow for return on both fixed and variable costs.

It is necessary to differentiate between planned and unplanned work. Planned work should whenever possible be paid for on a fixed price basis of unit rates (often called lump sum) work.

Unplanned work should be paid for in a combination of unit rates and dayrate/incentive type payment dependent on the ability to define what would be in its cope of work.

For instance mobilisation, demobilisation and rigup/down should be performed on a lump sum basis.

Due the uncertain nature of testing the contract rates should include provision for as wide a range of unplanned work as possible without continual recourse to the contractor's standard price lists which are usually the worst form of re-imbursable cost structures and provide the contractor with no incentive to perform.

The objective should be to pay for results meeting specified quality acceptance criteria.

Payment structure should be result-oriented not time-oriented.

4. Tendering

Once the contract strategy has been determined it is usual to tender. The specification of equipment required should be avoided. Specification of the deliverables should predominate. Tender documents which do not include specified equipment lists have been shown to have many benefits in stimulating the tenders to make commercially and technologically attractive offers.

5. Incentives

Various forms of bonus schemes are becoming common place in testing contracts in the North Sea. The type of bonus incentive scheme adopted will vary from Company to Company. An identification of the most common well testing problem areas within the Company is a good starting-point for devising an incentive scheme. Incentive payment schemes can be built around performance against quantifiable service quality-checklists covering such items as

·equipment rigged up, tested and accepted within a specified time;

·equipment rigged won and shipped back to contractor base within a specified time;

·pre-delivery and installation equipment acceptance criteria;

·percent equipment downtime, incidents

·compliance with Company and Contractor operations and safety procedures (e.g. PTW, Equipment Certification records complete and on-site, etc.;

·completeness of package;

·quality of data acquired and submitted;

·environmental incidents/liquid drop out.

Care should be taken not to make the incentives time-related but quality-related.

6. Contractor performance monitoring

Particularly in longer term contracts it is important to monitor contractor performance through effective performance benchmarking such as;

·no of fishes

·up-time;

·incidents;

·wireline miss-runs;

·pre-post cals out of spec;

·downhole tool failures;

·LTIs;

·Close-out speed of test review action items;

·No of rejected data acquisition incidents.

Hardware related

Equipment rigged up, tested and accepted within a specified time

Wharf delivery shipping checklist completeness (per cent)

Equipment rigged down, shipped back to base within a specified time

Number of items required after initial mobilisation

Certification records complete and on site

Per cent equipment downtime

Number of wireline miss-runs

Tool pre-calibration records complete in spec.

Tool post-calibration records complete in spec.

Data records submitted complete

HSE

Personnel's health and safety records up to date

Incidents (potential)

Environmental spills

Hazardous substance handling procedures followed

Permit to work procedures followed

Waste disposal procedures followed

Failure to achieve... for HSE will cancel the bonus scheme

1 General

Test objectives can vary from a single downhole sample to an extensive long duration reservoir limit test. This will form part of the well programme.

Stimulation and artificial lift are two methods of getting the well to flow; special provision may be required for these.

The purpose of a production test is to record the bottom-hole and wellhead pressures at a number of production rates, and simultaneously record the corresponding gas, condensate or oil rates. The main objectives of a test (including fluid sampling) of the reservoir zone are the determination of the following:

1.Static reservoir pressure and temperature.

2.The inflow performance characteristics of the well (i.e. drawdown as a unction of rate and average reservoir pressure).

3.The composition and P.V.T behaviour of the reservoir fluid.

4.Reservoir pressure build-up (to allow for well test analyses and skin determination) which in turn may lead to consideration of stimulation.

2 Test results

The results obtained from production testing can be used for a variety of purposes including the following:

1.The evaluation of an exploration programme - in particular the decision whether or not to continue.

2.Deciding whether to develop a discovery, to drill additional appraisal wells or to discontinue the drilling completely.

3.The provision of input data for the planning of a field development programme and/or for the design of production facilities and well completions. Well test data acquisition is a fundamental step in field development planning.

3 Test methods

Various types of testing schemes are available, and the selection of a particular method depends on the following factors:

* The type of well to be tested (i.e. oil and/or gas well).

* The amount of time that can realistically be allocated to the test.

* The use to be made of the test result.

3.1 Period 1: Clean-up (partial)

·To establish good communication between the wellbore and reservoir.

·To gain a first impression of well capacity and reservoir fluid composition.

3.2 Period 2: Initial build-up

·To measure the initial reservoir pressure.

·To restore reservoir equilibrium before embarking on the main flow period.

3.3 Period 3: Main flow period (eventually at stabilized conditions)

·To measure the productivity index or better still, establish one point on the inflow performance curve,

Surface samples for laboratory analysis to be taken during the final part of this period.

·To allow determination of skin factor, reservoir transmissibility and boundary effects. Only if flow is stable.

3.4 Period 4: Main build-up period

·To allow determination of skin factor, reservoir transmissibility and boundary effects.

·Measurement of the reservoir pressure may be desired if the initial build-up did not provide a reliable value.

·At the end of this period a gradient survey may render the gradient of the reservoir fluid at reservoir conditions.

3.5 Period 5: Additional flow period at different rates

·To take P.V.T samples (downhole), for oil wells only. To take (additional) surface samples.

 3.6 Period 6 to n: Additional flow periods at different rates

·To determine the flow rate dependency of skin factor, GOR, BS & W, sand production etc.

·To further define the inflow performance relationship. Although of interest, period 6 to n are generally not performed when testing oil wells. For gas wells however they are always recommended to assess non-Darcy flow effects (rate dependent skin).

The test design should obviously be related to the test objectives which are shown in bold characters in the preceding text. Although these test objectives are considered to be important during the exploration/appraisal phase of a reservoir, a different set of objectives is conceivable (e.g. additional flow period to determine stable H2S results, reservoir depletion, etc.).

These specifications apply to the design and fabrication of skid mounted production vessels, including all associated piping, fittings and valves, etc., mounted on the skid where intended use of the equipment for H2S service is at temperatures as low as -25°F. All material shall comply with NACE Standard MR-01-75, latest edition, "Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment".

1 Materials

1.1 General requirements applicable to all construction components

1.All carbon and low alloy steels in contact with sour fluids shall have a hardness of Rockwell C-22 maximum.

2.The carbon equivalent:

$C.E.=C+{{Mn} \over 6}+{{Cr+Mo+V} \over 5}+{{Ni+Cu} \over {15}}$ shall be £0.45% with Cmax = 0.23%.

3.The Charpy V-notch impact value at -25°F shall be 27 Joules minimum, average of three full size 10mm ´ 10mm specimens. The lowest value of any one specimen shall be 19 Joules. Procedure for selecting specimens and adjusting values when less than full size specimens are used shall be in accordance with ASME SA-333. The largest practical specimen of full, 2/3 or 1/2 size shall be used.

4.Material used for construction must be new.

5.No repair of defects in the tubular products will be permitted.

6.Continuous tubular sections shall be used between fittings. (Joining of short sections of tubular products is not permitted).

7.Materials shall be free of protective coating, both internally and externally.

8.Material shall be marked with steel dies or marking tongs which indent the metal only as noted. Otherwise, it shall be marked with paint stencil.

1.2 Vessels

Shell and heads shall be in accordance with ASME specification SA-516, Grades 55 or 65 plus Supplementary Requirement S5.

1.3 Pipe

1.All pipe forming an integral part of the vessel and thus normally falling within the jurisdiction of ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, shall be in accordance with ASME Specification SA-333, Grade 1 or 6.

2.All pipe flange connected to the vessel, but mounted on the skid, shall also be in accordance with ASME Specification SA-333, Grade 1 or 6 or as an alternative, may be made to API Standard 5L, Grade B, X42, X46 or X52, providing that it meets the "General Requirements" noted in Section 1.1, and if cold expanded, it has been tempered at 1150°F minimum after having been cold expanded.

1.4 Weld neck flanges

1.Material shall be in accordance with ASME Specification SA-350, Grade LF2, except it shall also comply with "General Requirements" noted above.

2.Identification: Flanges shall be fully identified in a permanent manner by one of the following methods:

a)Hot stamping (part above 1150°F) with rounded die impressions.

b)Cold stamping with rounded die impressions prior to final heat treatment.

1.5 Welded fittings

1.Material shall be in accordance with ASME Specification SA-420, Grade WPL-6, except it shall also comply with "General Requirements" noted above.

2.Identification: Fittings shall be fully identified in a permanent manner by one of the following methods:

a)Hot stamping (part above 1150°F) with rounded die impressions.

b)Cold stamping with rounded die impressions prior to final heat treatment.

1.6 Gaskets

1.Raised face flanged connection

a)Gaskets shall be spiral wound metal, asbestos filled, made in accordance with ANSI B16.5 Annex-E, Group 1b. Spiral round metal should be fully annealed, Type 316 stainless steel, Monel 400, or Inconel 600.

b)Metal hardness shall not exceed Rockwell C-20.

c)Gasket outside diameter shall be extended beyond the raised face by means of a centering ring equal in diameter to the bolt circle minus one bolt diameter (tolerance +0-1/8").

2.Ring joint flanged connection

a)Gaskets shall be fully annealed Type 316 stainless steel, Monel 400 or Inconel 600 made in accordance with ANSI B16.20 latest revision.

b)All ring gaskets shall be octagonal self-sealing type.

c)Hardness shall not exceed Rockwell C-20.

1.7 Valves

1.The following material shall not be used:

a)Low and medium alloy steel containing more than 1% nickel.

b)Free machining materials containing more than 0.08% sulphur.

c)Cold finished low and medium alloy steels, cold finished stainless steel and cold finished Monel K-500, in the cold finished condition.

d)AISI 400 Series stainless steel.

e)Precipitation hardened stainless steels, 17-4 PH and 17-7 PH. Use of other PH steels shall be subject to agreement between the Company and Manufacturer.

2.All steel materials for bodies and bonnets shall be capable of one of the following impact properties:

a)Charpy V-notch impact specimens when tested at -25°F shall exhibit a minimum of 50% shear fracture.

b)The Charpy V-notch impact value at -25°F shall be 27 Joules minimum, average of three full size 10mm ´ 10mm specimens. The lowest value of any one specimen shall be 19 Joules, except as modified by Section 4.4.

c)Cast materials shall conform to Charpy test requirements of ASTM A-352, Grade LCC. Forged materials shall conform to Charpy test requirements of ASTM A-350, Grade LF2.

d)All Charpy specimens shall be prepared and tested in accordance with ASTM E-23, latest edition.

e)Bolting for bonnets and flanges: see Section 13.2.8.

1.8 Bolts, studies and nuts

Materials shall be in accordance with ASTM A-193, Grade B7M for bolting and ASTM Specification A-194, 2HM for nuts. Bolts and studs made to this specification will be marked B7M and nuts will be marked 2HM.

1.9 Instrument piping

300 Series stainless steel in the annealed condition is acceptable for instrument piping as long as its hardness is less than Rockwell C-22.

1.10 Hammer union connections

Material shall comply with relevent sections of "General Requirements".

2 Design, fabrication, testing and inspection

Design criteria, fabrication, testing and inspection procedures shall comply with Section VIII, Division 1, of the ASME Boiler & Pressure Vessel Code and as dictated by the material specification noted heretofore. Heater coils shall in addition comply with API Specification 12K for Indirect Type Oil Field Heaters. Additional requirements are as follows:

1.No backing rings on welds shall be permitted and components having different internal diameters shall be internally bevelled to form a smooth transition from one internal diameter to the other.

2.Welds shall be 100% radiographed and the radiographs interpreted by a third party testing firm in accordance with standards set forth in Section VIII, Division 1, of the ASME Boiler & Pressure Vessel Code.

3.Drawings locating each weld with correlation to a radiograph record shall be furnished by the fabricator to the Company.

4.All welds shall be preheated of from 212°F to 300°F.

5.Only low hydrogen electrodes shall be used.

6.All welds shall be stress relieved at a temperature of 1150°F to 1220°F to reduce residual stresses and limit hardness to Rockwell C-22 maximum as required by NACE Standard MR-01-75, using the technique specified in UCS-56 of Section VIII, Division 1, of the ASME Boiler & Pressure Vessel Code.

7.These specifications shall apply to all piping mounted on the skid regardless of whether or not it falls within the strict jurisdiction of Section VIII, Division 1, of the ASME Boiler & Pressure Vessel Code as defined on page 1 of that document.

8.All pressure vessels shall have 1/8" additional material thickness for corrosion allowance.

9.All pipe shall have 1/16" additional material thickness for corrosion allowance.

3 Other design criteria

1.Skids;

a)Maximum width shall be 8 (eight) feet.

b)No component shall extend over the edge of the skid.

c)Skid end design shall permit loading and unloading unit with an oil field type winch truck over a rolling tailgate.

d)Lifting eyes shall be provided to allow handling unit with a crane.

2.Vessel supports shall be of sufficient strength and rigidity to support vessel when full and absorb any vibration that may be encountered in transit or on a offshore drilling unit.

3.Pipe brackets shall be of sufficient strength and rigidity, and number, to support the piping while the unit is in operation, as well as during loading and transporting the unit.

4.Protective framing, when ordered, shall enclose all components mounted on the skid and shall be strong enough to resist distortion in event of impacts as may occur when loading or off loading onto a floating vessel by crane. Lifting lugs shall be installed on top of framework for handling unit. The framework shall be removable from the skid by removal of fastening pins or bolts.

5.Enclosure: When ordered, the top and sides of the unit shall be enclosed. The top of the enclosure may be welded checker plate installed as a permanent part of the frame. The sides shall be easily removable panels. Galvanised sheet metal panels held in place by "U"-shaped channel members it top and bottom is an acceptable method.

4 Documentation

4.1 Tubular products, weld neck flanges, welding fittings

1.Certification that material used conforms to that specified.

2.Chemical analysis of each heat of steel.

3.Hardness test results from each heat/heat treatment lot.

4.Impact test results from each heat/heat treatment lot.

4.2 Gaskets

1.Certification that gaskets were made in accordance with specifications.

2.Type of materials used.

3.Hardness test results.

4.3 Valves

1.Certification that valves are made to the requirements as specified.

2.Chemical analysis of each heat of steel used in the valve bodies and bonnets.

3.Hardness test results for valve bodies and bonnets.

4.Impact test results for each heat/heat treatment lot for valve bodies and bonnets.

4.4 Steel bolding material

1.Certification that material is in confidence with these specifications.

2.Chemical analysis for each heat of steel.

3.Heat treatment.

4.Tension test results for each heat/heat treatment lot.

a)Minimum yield.

b)Tensile strength.

c)Elongation.

d)Reduction of area.

4.5 Pressure vessels

1.Pressure vessels shall be marked as specified by Section VIII, Division 1, of the Boiler & Pressure Vessel Code and shall be accompanied by the appropriate ASME Manufacturers Data Report.

2.Vessel shell and heads:

a)Chemical analysis for each heat of steel.

b)Hardness test results for each heat/heat treatment lot.

c)Impact test results for each heat/heat treatment lot.

3.Other reports covered under Section 4.1, 4.2, 4.3 and 1.7 of these specifications.

5 Painting

1.Blast all surfaces to white metal with appropriate abrasive per SSPC-SP-#5 or NACE Publication No. 53-1.

2.Apply one coat of Americoat Dimetcote #6 inorganic zinc, or equivalent, 3.5-6.0 mils dry film thickness and allow 24 hours drying time.

3.Apply one coat of Americoat #54 red coloured tie coat, or equivalent, 1.0-3.0 mils dry film thickness and allow 2-4 hours drying time.

4.Apply two coats of Company specified paint, 4.0 mils dry film thickness. Allow two hours minimum drying time between coats.

6 Condition of acceptance

A contract for equipment made to these specifications will not be considered complete and ready for payment unless the equipment is accompanied by a full set of certifications demonstrating compliance with material specifications, welding specifications and inspections procedures by a third party as set forth herein and as specified within referenced API, ASTM and ASME publications.

1 General

The majority of Well Testing carried out world-wide is in the 5000 psi WP regime. In recent years there has been a need to go deeper with resultant higher temperatures and pressures.

A description of equipment follows which essentially covers the 5000 psi through 15000 psi WP range. It is essential to ensure that a balance is achieved between what is available, and what is fit for purpose. The objective is to keep the completion string as simple as possible to attain objectives.

Three examples are given of possible Well Test strings in the 5000 psi, 10,000 psi and 15,000 psi WP ranges (see Section 11).

The well completion string should allow production testing at the following flow rates:

Gas/Gas condensate wells: 60 MMscf/d gas, 5000 bbl/d condensate,

Oil wells: 10,000 bbl/d with a GOR of about 1000 scf/bbl.

The well completion string should be designed to meet the following:

·flexibility and ability to meet all Petroleum Engineering objectives.

·simple design and relative ease to run.

·minimum wireline requirements.

Strings are usually designed for testing one or two, closely spaced, separate zones, in 7" OD and/or 95/8" OD casing sizes, by using a selective, wireline set permanent type, packer arrangement.

Differing tests will dictate the exact description of a test string. Some considerations will be:

1.Maximum expected pressures and temperatures. If pressures are not expected above 5000 psi, 'x' line wireline equipment will suffice as will a 5000 psi Xmas tree (e.g. on a land location).

2.Economics versus time could be a constraint that determines sophistication of data acquisition, e.g. bottom shut-off tool, amerada or bundle carrier, memory or surface read out.

In general, the well completions string would allow the following:

·Perforations with a 2 1/8" through tubing gun requiring a minimum bore of 2 1/4".

·Accurate recording of downhole temperatures and pressures.

·Wireline operations to the bottom of the well.

·Control of the well at any time through killing, use of blow-out preventers or operation of a subsurface safety valve.

A 31/2" tubing string is normally considered suitable for production testing; when higher rates are programmed a 5" tubing string is recommended. When the well is drilled in a new area it is mandatory to be prepared for H2S gas; in this case the material for the tubing should be grade L-80. All tubing accessories should be suitable for sour service.

For wells with a TD below 10,000 ft it is advisable to have the top part consisting of a stronger tubing (i.e. 31/2", 12.95 lbs/ft) On floating rigs the tubing from rig floor to BOP stack is prone to buckling and should therefore be rigid; 41/2"-19.2 lbs/ft is recommended. Hydril tubing connections are proven to give good service especially for repeated stabbing and make-up which is usually the case during testing operations. In addition, the integral tubing connection (no coupling) reduces the potential chance of a connection leak by 50%.

A detailed standard list of necessary completion equipment and completion sketches can be found in Section 11.

2 Subsurface equipment

2.1 Well completion items below the packer

The following items are used:

2.1.1

The wireline re-entry guide is chamfered on the outside as well as the inside to guide the tubing-string into the packer bore, when approaching the packer during tubing running and re-entry of wireline/Schlumberger tools.

2.1.2

A pup-joint to protect tandem pressure and temperature recorder. If sufficient space is available to the top of the perforations, a full joint may be run. Sometimes the formation pressure is very low and the well is not expected to unload easily. In this case it is important to keep the height between the packer and the perforations as short as possible and the protecting joint should be limited in length or left out completely.

2.1.3

A no-go nipple is used to hang off pressure/temperature recorders on a corresponding lock.

2.1.4

A 27/8 in. ´ 10 ft perforated nipple to provide flow-passage above the recorders.

2.1.5

Landing nipple: a plug will be set in this nipple when it is necessary to sample the tubing contents of a well which is incapable of natural flow to surface. Once the plug has been set, the tubing contents can be circulated to surface by pumping down the annulus and through the circulating device in the tubing.

2.1.6

As standard, a 20 ft long locator seal assembly will be used with an ID = 3 in. and OD = 4 in. to fit both 7 in. and 95/8 in. permanent packers.

2.1.6.1 Packer

Use of a permanent packer is mandatory for the following reasons:

There is hardly any swabbing effect while pulling the string. A retrievable packer has to be pulled slowly to avoid swabbing. The permanent packer will not release due to tubing movement caused by pressure or temperature if spacer seal-assemblies are used.

On a number of occasions retrievable packers have released after correct setting due to tubing movement during pressure testing, stimulation or normal flowing. They should be avoided, particularly on floating rigs.

2.1.6.2 Packer configurations

The following various permanent packer configurations are possible:

1.A flapper-valve can be fitted at the bottom of the Baker D or DA packer; this valve closes when the tubing-string is retrieved. Use of the flapper valve is not recommended because the mule-shoe may become damaged while stabbing the completion string into the packer and by holding up on a closed flapper which may have high pressure below it.

2.A junk-pusher can be part of the packer assembly and is fitted at the bottom to clear the casing-bore from mud or removable obstructions, and acts as a feeler. As other necessary extensions are usually fitted to the bottom of the packer the junk-pusher is not normally part of the packer and a separate scraper run, should be made prior to packer setting.

3.Where temperature differences in the well will cause appreciable changes in tubing length the seal assembly may be extended to some 20 feet to accommodate changes in tubing length.

4.If a permanent packer is to be milled-out, a packer milling tool can be used. This tool mills the outer part and slips of the packer; the packer body and any attachments below can be picked up by the catcher sleeve, which is part of the milling tool.

In the top of the packer a plug can be set, on wireline, tubing or drillpipe, converting the packer into a (semi)-permanent bridge plug.

The Company has good experience with Baker Permanent Packers for well test and permanent completions.

2.1.6.3 Well completion items above the packer

Items run above the top packer will essentially depend on the pressure rating of the surface wellhead equipment, which in turn is determined by the maximum pressure expected during the well test. The surface tree could be 5000 psi, 10,000 psi or 15,000 psi rated, and downhole accessories will therefore be chosen to suit. Besides the three examples given in Annex A, which were all done from offshore drilling vessels, it is also usual to have standard equipment as specified below, for land well testing operations.

2.1.7 Gauge carriers (above packer)

Several types of recorder carriers are in use to accommodate different string configurations. Where both mechanical and electronic gauges are used, the size varies from 37/8" OD to 51/2" O"D for standard and H2S service. There are inside/outside reading options and are rated to 15,000 psi WP.

2.1.8 Downhole shut-in tools

Again, several types of downhole shut-in tools are available on the market, such as the Schlumberger MUST (multiple Shut-in Tool) which allows up to 12 flow and shut-in cycles of pressure monitoring.

2.1.9

A 31/2 inch no-go nipple and test tool are used for pressure testing the completion string. This nipple is preferred for pressure testing the completion string due to the no-go feature being rated for very high tubing test pressures. A further advantage is that these-nipples can also be used with 31/2 inch Hydril Ph-6 tubing 12.95 lb/ft, which has a small ID.

2.1.10 Sliding Side Doors (SSD) size 31/2 inch

Under normal operating conditions during well testing, SSD's are usually closed. During testing the SSD will only be open for short periods. Generally the force required to open the SSD, after a long period of being closed, will be fairly high. This is caused by possible swelling or hardening of the elastomer packing material. By jarring-up, a larger force can generally be applied on the positioning tool than when jarring down and therefore is preferred for well testing purposes.

Another advantage of using this type of SSD is that when problems occur to close the SSD (for instance when the jar down force is small due to heavy brine), a less viscous, lighter fluid can be spotted over the SSD to increase jar down action.

2.1.11

A 31/2 inch Landing nipple is installed below the SSD. It can be used to set a plug before disconnecting the SSTT as an additional safety measure or it can be used for pressure testing the top part of the tubing string. The ball valves of the SSTT have to move downward before opening. When a plug is installed in a nipple too close to the SSTT, fluid lock can prevent its opening. Therefore this nipple should be placed a minimum 500 feet below the SSTT.

On fixed platforms (jack-up rigs) and land wells the tubing is hung-off by means of a standard tubing hanger nipple inside a tubing hanger-spool. The extended neck of the tubing hanger nipple is packed off in a seal flange with double P-seals. On top of this seal flange the production test contractor's Xmas tree is positioned by making use of a flanged X-over spool.

On floating rigs the tubing is hung-off by means of a fluted hanger inside the 95/8 inch or 7 inch wear bushing. A slick joint, positioned opposite the lower 5 inch piperams, connects the SSTT to the fluted hanger. During production testing the rams are closed around the slick joint to shut-off the annulus.

The tubing from the SSTT to the surface should be very rigid to prevent buckling. It is recommended that 41/2 inch Hydril PH-6 19.2 lbs/ft is used.

This section deals with the equipment which is run between the pipe rams and the rotary table and comprises:

2.1.12 SHORT single-shot hydrostatic overpressure reverse tool

The SHORT tool is a simple device opened by one cycle of annulus overpressure. It has few working parts, consisting of a moving mandrel inside a housing containing two atmospheric chambers. A rupture disc communicates from the annulus to the lower atmospheric chamber. It is a compact, reliable tool that fits ideally in any cased hole test string. The SHORT tool cannot be closed once it is opened and an incidental overpressure of the annulus could open the tool.

2.1.13 MCCV multi-cycle circulating valve

The MCCV tool is a reclosable valve operated by tubing pressure and used for reversing or circulating. It is similar to the MIRV tool but differs in that it is not rate sensitive for closing. To close, the tool uses changes of flow direction rather than rate changes. It has three positions:

·Closed, no communication between annulus and tubing.

·Open, annulus to tubing, to allow reverse circulation.

·Open, tubing to annulus, to allow circulation.

The MCCV tool has an inner mandrel with a set of ports that can align with either reversing or circulating ports. Each set of ports has flow restrictors that allow flow in only one direction. This can create sufficient backpressure to close the tool. The tool can be preset on 6 or 12 cycles, depending on the expected pressure tests on the string. When internal pressure exceeds annulus pressure by 500 psi, the indexing system cycles.

After a preset number of cycles, the tool opens and the string contents can be reversed out through four 1/2 in. ports. When pumping starts, the reversing port restrictors limit flow, causing a pressure difference that moves the inner mandrel into the spotting position. At the end of pumping, the applied pressure is bled off and the tool can be used for spotting nitrogen or stimulation fluids. The main benefit of the MCCV tool is that it is completely unaffected by the operation of the annular pressure-operated tools.

MCCV specifications :

ID17/8 in.21/4 in. fullbore/ OD5 in.5 in. / Length84 in.74.1 in. / ServiceH2S/acidH2S/acidª / Maximum pressure15,000 psi10,000 psi§ / Temperature350°F / Tensile strength at minimum yield530,000 lbf / Make-up torque6000 ft lbf4000 ft lbf/ Operating pressure500 psi above hydrostatic / Flow partsfour, 1/2 in. / Maximum pump rateunlimited / Weight350 lbm / Top connection31/2 in. API IF box / Bottom connection31/2 in. API IF pin / Max. number of open reversing ports6 (1/2 in. diameter) / Spotting rate3/4 bbl/minute/port¨ /

ª As per NACE MR-01-75§ Maximum working pressure differential (burst and collapse) on 67% of minimum yield¨ Recommended maximum flow volume - 3/4 bbl/port. These ratings are for 16.5 lbm/gal mud

2.1.14 PORT pressure-operated reference tool

The PORT tool is a pressure reference tool for the PCT flow control valve and is designed for use with both permanent and retrievable packers. It is run in the hole in the open position for fluid by-pass. Raising annulus pressure above hydrostatic pressure bursts the rupture disc and raises the mandrel, which seals the by-pass and traps the reference pressure for operation of the PCT valve. Using the PORT tool instead of the HRT tool, which is closed by application of string weight, allows the test string to be run in tension for stinging into a permanent packer.

The test string is greatly simplified by eliminating the drill collars, which the HRT tool requires for weight, and the ability to sting into a permanent packer eliminates the need for slip joints.

Once the PORT tool has been closed, it remains closed. The tool is balanced to inside diameter pressure and therefore is not affected by applied pressure encountered during well stimulation.

For safety, any pump overpressure and reference pressure trapped in the PORT and PCT tools is automatically bled off through the PORT relief valve as the test string is pulled out of the hole.

2.1.15 PCT pressure control tester tool

The PCT flow control test is hydraulically operated. Because no motion of the string is necessary, this tool is ideal for offshore operations or when testing in deep wells or in deviated wells. It is opened by applying pressure on the annulus. A spring and a nitrogen charge provide a positive closure. The nitrogen is compressed by hydrostatic pressure by means of a floating piston while running in the hole. This allows a low nitrogen precharge to be used at surface for improved safety. The PCT tool can be opened as many times as necessary for multiple flow and shut-in periods, for stimulation and for wireline perforating and sampling. The ball valve holds pressure from above and below; therefore, the string can be pressure tested while running in the hole.

The PCT tool can be permanently closed by using the overpressure rupture disc. This safety feature prevents the annulus pressure from increasing in an uncontrolled manner.

2.1.16 DataLatch system

The DataLatch system comprises a fullbore pressure and temperature downhole recorder system with optional surface read-out capabilities. It allows downhole recording during flow or stimulation periods. The two components of the DataLatch system are the MSRT MultiSensor Recorder/Transmitter tool and the LINC Latched Inductive Coupling tool.

The MSRT tool is a 5 in. ´ 21/4 in. fullbore, pressure and temperature, battery-operated downhole recorder. The LINC tool is designed to communicate with the MSRT tool to provide real-time surface read-out, retrieving previously recorded data and downhole recorder reprogramming.

The DataLatch system has definite advantages

·It is the only DST pressure acquisition system available with an outside diameter less than 5 in. This is the maximum OD size run in 7-in. heavy-weight casing.

·Without wireline in the pipe, the system is a true 21/4 in. ID fullbore tool, which is valuable when stimulating.

·With the LINC tool latched in place, the flow area remains equivalent to a 21/4 in. diameter fullbore.

·Its ability to monitor pressure above the flow control valve, below the valve and in the annulus ensures better quality control monitoring of the drillstem test in progress.

2.1.17 MSRT multisensor recorder/transmitter tool

The MSRT tool is the only fullbore, 21/4 in. ID electronic recorder available. It can simultaneously record three pressures; above the flow valve, below the flow valve, in the annulus or any combination of the three. One temperature measurement is also recorded. There is no obstruction to the flow of the fluid in the test string, which can be particularly valuable during the simulation phase of a test-treat-test or reperforation operation. The tool electronics are installed in a test string sub directly above the control

2.1.18 Subsea test tree (SSTT)

The purpose of this tool is to provide a means of shutting in the wells at the subsea BOP and then unlatching the upper string so that the rig can be moved in the event of a problem with the vessel.

The features of the tools are as follows: (E-Z tree used as example).

The E-Z Tree valve latch assembly consists of a valve assembly and a latch assembly, landed in the BOP stack and hydraulically controlled from the surface by a hose bundle running through the riser annulus. The valve and latch assembly is only 9 ft long, making it easy to handle and store. The valve assembly is less than 42 in. long (29 in. for 15,000 psi assemblies), making it possible to close the blind rams above the valve assembly after latch release in virtually any BOP stack. The complete hydraulic mechanism is contained in the latch, with no communication of hydraulic fluid to the valve and therefore no danger of contamination by mud or well fluids.

Pressure applied through a third hydraulic line can be used to help close the ball valve, to move or shear debris or to cut heavy wireline cables. The ball valve is capable of cutting wireline cable and coiled tubing. Features of the E-Z Tree assembly are:

·The hydraulic circuits are hydrostatically balanced, operation is unaffected by water depth.

·The valves are normally closed, and pressure is required to keep them open. The valve operators are removed with the latch when disconnected.

·The primary latch release is operated hydraulically from the control console at the surface. In addition, mechanical release is possible by rotating to the right to a predetermined torque.

·The valve can always be pumped open to kill the well.

·The design of the E-Z Tree tool allows injection of hydrate inhibitors, thus preventing possible jamming of valves when testing gas wells.

2.1.19 Lubricator valve

During offshore tests it is useful to perform wireline operations, and it may be an advantage to have a valve available that avoids the use of a lubricator above the flowhead. This special valve is called the lubricator valve, and it should be located at least 30 m below the flowhead. It enables the upper part of the test string to be used as a lubricator during wireline operations.

The lubricator valve is balanced; in case of hydraulic failure it remains in the last position (open or closed) in which it was placed before the failure occurred. An internal valve equalises the pressure across the lubricator valve prior to its opening. The equalisation is progressive to avoid the violent surge of well fluid inside the lubricator space. If the valve has been left in the closed position it is possible to open it by pumping fluid from the surface.

The lubricator valve is a ball valve that closes and seals with pressure applied either from above or below:

·To withstand well pressure when wireline tools are introduced or removed from the upper part of the test string, which is used as a lubricator.

·To test flowhead and surface wireline equipment.

2.1.20 Retainer valve

The retainer valve isolates the well fluids under pressure in the pipe above the E-Z Tree tool and prevents communication to the riser should it become necessary to disconnect. This is particularly important in deep water because it prevents pollution and eliminates dumping of high pressure gases into the riser. The retainer valve is run just above the hydraulic assembly and opens and closes in conjunction with the E-Z Tree valves.

3 Surface equipment

3.1 General

The surface equipment required to perform a well test differs considerably depending on the type of environment, the well condition and special requirements. Considerations include:

·Land: arctic, desert, jungle, etc. / ·Offshore: arctic, sea, swamp / ·High or low pressure, high or low temperature / ·H2S, CO2 or both / ·Gas, oil, water or all combined / ·Viscous or foaming oil / ·High flow rates / ·Populated or sensitive areas

On land, the surface testing layout is usually simplified. Burners are replaced by flare lines made from tubing, and compressors are not required. However, burners may be used on land in areas such as the jungle, where space is limited, or in densely inhabited areas, where any pollution is intolerable. Testing equipment and the methodology used are combined and adapted to meet various situations.

The production test equipment is normally rented from a production test contractor, the most well known being Baker, Expro, Schlumberger, Geoservices and Haliburton. A typical well test layout is shown in Section 5 and test tree layouts for floating and fixed rig installations are shown in Section 5. It is recommended to have a complete production test package on hire during the exploration drilling campaign. Although there is a chance that the equipment will not be used, the risk of waiting for production test equipment in view of the very high rental rates of drilling units is too great.

3.2 Surface test tree (STT)

The purpose of the STT is to direct and control the flow of well effluent from the tubing to the process equipment. The STT is placed above the Swivel and Hydraulically Actuated Lower Master Valve.

The STT is described in the following:.

3.2.1 Layout

·Main body containing a Master and Swab Valve placed in a monoblock assembly.

·Kill wing having a monoblock 90° elbow and gate valve. A check valve would be placed between the Gate Valve and the kill line.

·Flow wing, again a monoblock 90° elbow leading to a hydraulically actuated gate valve which is capable of opening against total differential pressure.

3.2.2 Valve data

McEvoy model "E-2" Valves would be used in the construction of the STT having the following features.

·Self sealing metal-to-metal gate valves

·Sealing groove provides secondary seal

·Pressure balance stem reduces operating torque

·Field replaceable seats

·Proven equipment

For extended use at temperatures of 300° the valve working pressure should be downrated to 14,500 psi. This limitation will have to be taken into consideration in designing the test programme.

3.2.3 Chemical injection facility

Chemical injection is provided by an injection port in the main monoblock assembly between the master and swab valve. Dual check valves are incorporated in the system and fittings are of a 9/16 " autoclave variety.

3.2.4 Variable production choke

It would be feasible to have a variable production choke placed in the flow wing elbow. This would have the dual benefit of controlling flow at the STT and producing a cooling effect in the down stream leg.

Due to the limited access to this equipment when it is rigged up it is suggested that a hydraulically operated choke (Masterflo) be used, however, it must be pointed out that an installation of this type will increase the size, weight, cost and exposure to damage.

3.2.5 Elastomers

All elastomers are of a Viton construction and are suitable for use up to 350°F.

3.2.6 Connections

The STT assembly will be fitted with the following connections:

·Kill wing: Grayloc connection

·Flow wing: Grayloc connection

·Landing string X-over: Hydrill PH-4 pin

·Top connection: Modified stub Acme box

3.3 Swivel

The swivel is placed below the Surface Test Tree and allows the string to be rotated independently of the STT so that packers can be set with the STT in place.

A typical swivel assembly comprises an upper inner mandrel rotating inside a lower outer mandrel with elastomers providing the sealing mechanism.

In very high pressure applications, two sets of seals are incorporated. These seals are located below the bearings and allow the tool to swivel under low pressure. When tension is applied to the tool during normal testing operations sealing is transferred to a metal-to-metal seal above the bearings.

Tubing pressure will also act to energise the seal so that a greater sealing force is provided when high tubing pressures are present. This will prevent the swivel turning, but will maintain metal-to-metal sealing integrity.

3.4 Hydraulically operated lower master valve

The purpose of this valve is to act as an additional master valve and is placed below the swivel. The valve is connected via an Emergency Shut Down (ESD) Panel to a number of remote manually operated shut down pilots. The lower master valve is a fail-safe valve and is capable of cutting a wire in the well.

The valve is independent of the automatic shut-down system (Surface Test Tree flow wing valve) and would be closed manually via the shut down panel as a last resort in the event of a failure in the surface system and it should be noted that the valve also protects the swivel in the event of a leak.

The valve comprises a housing, closing spring, valve operator mandrel and ball valve with metal-to-metal seals. It is a normally closed valve so that control line pressure forces the operator mandrel down compressing the spring and rotating the ball into the open position. When the control pressure is reduced the reverse occurs and the ball rotates to the closed position.

If wireline is present, the assist closure facility can be used and pressure is applied to an assist close line so that the ball cuts the wire and continues into the closed position.

A lock open facility is also present so that accidental operation of the manual shut-down system will not close the valve during operations when wire is in the well either prior to opening the well or at the conclusion of the test. In the event that emergency closure is required during these operations the lock open feature can be overridden by application of hydraulic pressure to the assist closure line.

3.5 Coflexip production hose

The purpose of the Coflexip Hose is to allow well fluids to be passed from the STT to the choke manifold. Coflexip hoses are generally used for this application on floating rigs because of the relevant movement between the STT and the rig floor. In areas of significant tidal ranges or during rough weather this motion can be considerable and a rigid pipe set-up is impractical.

3.5.1 Hose specifications

3.5.1.1 Construction

The hose is constructed of a number of concentric tubes that form a laminate that creates a pressure boundary, having the ability to withstand high temperatures and offers good resistance to external wear and tear.

Records should be kept recording use of the Coflexip hose in all applications where flowing temperatures exceed 220°F.

3.5.1.2 Chemical resistance

The hose will have resistance to the following substances throughout the temperature range: / ·Most acids and bases / ·Salts / ·Oxidising agents / ·Halogens / ·Alcohols / ·Chlorinated solvents / ·Aliphatic hydrocarbons / ·Crude oil

The hose, however, will be non-resistant at high temperatures to: ·Amins / ·Concentrated sulphuric and nitric acids / ·Sodium hydroxide / ·Ketones / ·Esters / ·Dimethylacetamide / ·Dimethylformamide / ·N-methylpyrrolidone

3.5.2 Hose connections

Grayloc metal-to-metal connections will be used on the hose. These connections are described in detail in Fig. 1937.

3.5.3 Certification, records and maintenance

Incorporation of flexible high pressure hoses in high pressure and temperature testing creates potential hazards because the production hose will be the weakest link in the pressures/temperature rating chain. It will be important to limit the flowing well temperature to less than 260°F for continuous use of the hoses.

Use of a hose of this type should not exceed the manufacturers recommendations. Stringent records will be kept detailing the use of the hose, so that exposure to temperature, pressure and corrosive fluids is monitored. In addition, for routine maintenance and testing, the hose will have to be internally inspected prior to, and after every job, detailed records of maintenance will be kept.

3.6 Data header

A data header is a length of pipe equipped with several connections for instruments that require measurements such as:

·Wellhead pressure

·Wellhead temperature

·Sand control data

3.7 Choke manifold

A choke manifold is used principally to control the flow rate. It consists of a number of valves and fittings arranged in such a way that the flow can be directed in one or two directions. This facility allows the flow through one or two choke boxes. Each box can accept different types of chokes fixed or adjustable. On the fixed side, calibrated choke beans are used. Each bean is manufactured accurately to a specific size, usually in graduations of 1/64 inch and is screwed into the choke box. This means that a specific flow rate on a specific choke size is reported. On the adjustable side, a variable choke is fitted to permit the change of the fixed choke without interrupting the flow during the change. The adjustable choke is a variable geometry orifice that can be reduced or enlarged without isolation of the choke box.

Both choke boxes utilise tungsten carbide or ceramic orifices to avoid erosion during clean-ups when sand particles may occur.

The choke manifold is also equipped with several pressure taps for recording pressures upstream and downstream of the choke and for monitoring the temperatures upstream and downstream of the choke boxes.

3.7.1 Nominal rating

Various chokes can be provided. The rating must complement the heater placed downstream as under certain conditions choking may take place at the heater. The choke at the heater is independent and different from the chokes in the choke manifold.

3.7.2 Valves

The choke manifold is a four valve assembly incorporating McEvoy "E-2" valves. It should be noted that the "E-2" valves are rated at 14,500 psi w.p. at a temperature of 300°F.

3.7.3 Connections

The inlet and outlet connections of the choke manifold of 15,000 psi w.p. shall be Grayloc type connections. Elastomers shall not be used.

3.7.4 Bleed-off valves

One bleed-off valve is provided per choke box so that pressure trapped between two closed valves can be bled down prior to attempting to remove the choke end cap. The McEvoy valves are also equipped with bleed-off valves.

3.7.5 Chemical injection

Chemical injection can be provided either in the upstream or downstream leg of the choke manifold. Injection points are also provided with a double check valve assembly in the event of failure of the injection hose or pump.

Hydraton double acting, air operated, high pressure, hydraulic pumps will be used for chemical injection. Each injection unit comprises a skid with two pump assemblies and chemical reservoir tank.

3.8 High pressure pipe work, hoses and piping

High pressure pipe work will convey the well fluids from the choke manifolds to the heater inlet. This pipe work will have the following features:

1.Pressure rating: 15,000 psi w.p.

2.Temperature rating: -28°F to 350°F

3.Nominal size: O.D. 3.5" and I.D. 2.3"

4.No chiksan, pipe work comprises straight sections or elbows

5.No threaded sections, all welded

6.Metal-to-metal seals (see below)

3.8.1 Hoses and piping

The various elements of the well testing set-up are linked together through different pipes and hoses selected according to service pressure, flow rate, and relative movement and lay-out equipment.

The service pressure of pipes and flowlines is dictated by the highest expected pressure at a particular point of the well test set-up. This will vary from as high as 15,000 psi (1034 bars) between the STT and choke manifold for a high pressure well test to 500 psi (34 bars) between the separator and burners.

The flow rate is used to determine the pipe size. Pipe diameter is usually 2 in. or 3 in. upstream of the choke and 3 in. downstream. 4-Inch piping is sometimes used downstream of the separator for high rate gas tests. Piping is referred to by its nominal size. The actual inside diameter can be considerably smaller for heavier pipe grades.

Piping routes should be kept as straight as possible to decrease pressure losses, erosion and cost. However, to accommodate relative movement of well test elements and equipment lay-out, a typical set of piping consists of a mixture of rigid (straight lengths and elbows)) and articulated (Chiksan) piping or flexible hoses. On high pressure tests, flexible hoses are normally preferred to Chiksan hoses because they are more reliable and relatively maintenance free. Piping elements and hoses are connected through "Weco" wing unions. These unions are designated by their nominal size and figure number (e.g. 3 inch 1002); the first two digits refer to the test pressure and the last two digits refer to the sealing method. For high pressure tests, a 15,000 psi "gray-loc" quick union is used. Where economically feasible dynetor (FMC product) connectors should replace Chiksans and Wecos.

3.8.2 Grayloc metal-to-metal seals

All high pressure pipe work should be equipped with Grayloc metal-to-metal seals as these are not susceptible to pressure/temperature degradation as compared to elastomers. A schematic of the parts of this seal is shown below. The Grayloc connector has three components: a metal seal ring, hubs and a clamp assembly. The seal ring resembles a "T" in cross-section. The base of the "T" is the rib that is held by abutting hub faces as the connection is made up. The top of the "T" forms the lips that seals against the inner surfaces of the hubs.

In assembly of the connection, the clamp fits over the two hubs and as it draws the hubs together, the seal ring ensures proper seal alignment. As the hubs are drawn together by the clamp assembly, the seal rig lips deflects against the inner sealing surface of the hubs. This deflection elastically loads the lips of the seal ring forming a self-energised seal.

3.9 Heat exchanger

3.9.1 Heaters and steam exchangers

These are used to raise the temperature of produced fluids for hydrate prevention, viscosity reduction and breakdown of emulsions.

Heaters can be classified as follows:

·Direct heaters, where the heating source is in contact with the fluid to be heated.

·Indirect heaters, where heat is transmitted to a heating medium, which in turn heats the fluid.

·Steam heat exchanger.

·Electrical.

Direct heaters are not recommended for use in well tests, due to the potential hazard of production coming into contact with an open flame.

Indirect heaters, fired by natural gas or diesel are the most commonly used, alongside steam heat exchangers, which are preferred where available and feasible (space). Electrical heaters require extreme care when used, and must be checked for proper zone classification (control box, etc.).

3.9.2 Hydrate prevention

Natural gases contain water vapour, and under certain choke-flow conditions the expansion is sufficient to lower the temperature of the flow so that hydrates are formed (particles of water and some of the light hydrocarbons in the natural gas become solid). This can become a serious problem if freezing occurs in the surface equipment; ice can block the chokes, the various valves and the flowmeters and apply full wellhead pressure to downstream equipment that may have a lower pressure rating. H2S and CO2 promote the formation of hydrates.

3.9.3 Viscosity reduction

High viscosity is a problem during testing because it impairs the flow of liquid through various lines and reduces separation and burning efficiency. Heating the fluid helps control the problem.

3.9.4 Breakdown of emulsions

It is necessary to separate the volume of oil from water so that it can be measured. Under certain conditions oil and water are miscible and will not separate unless the temperature of the mixture is raised. A heater helps to alleviate this problem.

3.9.5 Heater details

·Capacity: 3-4 MM btu/hr

·Pressure rating

-High pressure coil: Full well pressure

-Low pressure coil: 10,000 psi, 5,000 psi or 3,000 psi w.p.

·Connections: Grayloc hub clamp

3.9.5.1 Safety and monitoring devices

The heater will be equipped with the following safety devices:

·Heater body

-Rupture disc 110% body w.p.

-Safety relief valve @ body w.p.

·Steam lines

-Non return valve on steam inlets

-Degasser skid to monitor hydrocarbon in steam condensate line (returns).

Temperature will be controlled by a thermocouple device linked to a control valve on the steam inlet line. Inlet and outlet temperatures will also be recorded by the Surface Data Acquisition System.

Because the heater can withstand full well pressure up to and including the adjustable choke body, there is no need to provide over-pressure protection upstream of the heater. A high pressure pilot (PSH) linked to a ESD system will be placed downstream of the heater to protect the low pressure coil and separator. Additionally, a relief valve and vent line would also be present between the separator and heater in the event that pressure builds too quickly for the ESD to react. This vent line should be sized to handle full well production.

3.9.6 Valves and adjustable choke

McEvoy "E-2" valves will form the inlet manifold with the ability to by-pass the heater or shut-in the well at the inlet valve.

A Masterflo adjustable choke will be used to choke between the high pressure and low pressure coils.

SafetyDiesel shutdown valve activated by pilot light stoppage Flame arrestor on burner air inletDiesel shutdown valve activated by pilot light stoppage Flame arrestor on burner air inlet

3.10 Separator

3.10.1 Horizontal test separator

An intrinsic requirement for test separators is the capability to handle exploration wells where the nature of the effluent is not known. Consequently, test separators must be able to treat gas, gas condensate, light oil, heavy oil, foaming oil, as well as oil containing water and impurities such as mud or solid particles. A range of test separators has been designed for high content H2S service (sulphide stress cracking).

The 1440 psi, 42 in. ´ 10 ft. "elastique" separator was designed in two versions: one for temperatures above -20°F(-28°C) and the other for low temperatures to -50°F(-45°C). Separators have the following characteristics:

·A test separator should permit separation, metering and sampling of all elements or phases of the effluent.

·It should be able to separate the different types of effluent.

·It should also accept products containing quantities of impurities, such as muds and acids, when the well is cleaning up.

·The separator should be as compact as possible to facilitate transportation to the site and to be easily accommodated on offshore platforms.

·Adequate protective frames are also necessary for transportation as well as for protection against corrosion in tropical climates and marine environments.

·A test separator should have appropriate auxiliary piping for connection onsite.

Because of the versatility required, test separators are not expected to achieve a separation as perfect as production station separators. However, they must perform in such a way that the separated elements can be reliably metered.

For a station separator, the following additional conditions must be met if the gas capacities are guaranteed on the basis of liquid carry-over not to exceed 0.1 gal/MMft3:

·Liquid particle size in the moving gas stream is 150 microns or larger.

·Temperature of the gas stream is above the cloud point of the oil.

·Temperature of the gas stream is above the hydrate temperature.

·No foaming.

·Non heading flows.

3.10.2 Safety devices

The separator is equipped with the following safety devices:

·One High Pressure Pilot (PSH) linked to the ESD system and STT flow wing valve. This valve will be set at 1,300 psi and is designed to protect the vessel and upstream pipe work. In the event of the pilot being tripped the ESD System will shut the well in at the actuated wing valve.

·Two 3" ´ 4" Safety Relief Valves set at 1,440 psig. In the event that separator pressure reaches 1,440 psig these will open and vent the separator to the booms via a 4" vent line.

·One high liquid level alarm. This will alert the well testing personnel and the liquid level can then be adjusted manually to bring it back into the normal operation range.

·One low liquid level switch linked to the LCV with audible alarm. This level is more critical than the high level because if the liquid levels drops to the extent that gas is allowed to flow through the liquid lines, that may at some point during the test lead to the surge tank, there may exist a danger that the venting capacity of the surge tank is less than the amount of gas flowing into the vessel. In a situation such as this the working pressure of the vessel could easily be exceeded.

3.11 Gauge/surge tanks

3.11.1 Gauge tank

There are a number of ways to measure the liquid flow rate from the separator. These include inferential meters, positive displacement meters and gauge tanks.

The gauge tank is a non-pressurised vessel used to measure low flow rates or calibrate differential or positive displacement meters. The gauge tank is a double-compartment vessel. One compartment can be emptied by the transfer pump while the other compartment is being filled. The gauge tank is never used when H2S is present because gas released from the gauge tank is vented to atmosphere and would endanger personnel. Sight glasses with a scale allow the change in volume to be calculated since the physical dimensions of the gauge tank are known. Safety features include flame arrestors on each vent of the gauge tank and a thief hatch in the event the vessel is accidentally overpressured. A grounding strap is attached to the gauge tank to prevent a build-up of static charges. Shrinkage may be controlled by a thermowell provided on each compartment of the gauge tank.

3.11.2 Surge tank

The surge tank was originally designed as a secondary stage of separation but now serves an additional function because it can replace a gauge tank when H2S is present.

The surge tank is a pressurised vessel and is used to measure flow rates. The surge tank is a single-compartment vessel with an automatic pressure control valve on the gas outlet line to maintain a backpressure that can be set to any pressure up to 45 psi. Sight glasses allow the change in volume to be inferred with knowledge of the physical dimensions of the surge tank. A high- and low-level alarm warns when gauging will be stopped.

Safety features include a safety relief valve in the event the vessel is accidentally overpressured (the maximum working pressure is 50 psi). A grounding strap is attached to discharge the surge tank in the event of any static charges. An accurate measurement of shrinkage and meter factor can be obtained at the surge tank.

When designing the safety devices on the surge tank, the following should be addressed:

3.11.3 Safety devices

·One High Pressure Pilot (PSH) linked to a secondary ESD panel that is linked with an actuated shut-down valve on the separator oil outlet. If the pilot senses high pressure in the line from the separator to the surge tank, a condition that would exist if the liquid level was allowed to fall, allowing gas to flow to the surge tank, the shut-down valve would close and prevent any further flow into the tank before the pressure exceeded the design working pressure. Any gas that managed to get to the tank would then be vented by the normal means.

·One 3" ´ 4" Safety Relief Valve set at 50 psig. In the event that vessel pressure builds up to 50 psi the valve will open and vent overboard via the vent line.

·One high level audible alarm (LSH). This will alert the well testing crew if the liquid level approaches the top of the sight glasses.

·One low level liquid audible alarm (LSL) that will sound when the liquid falls too low.

3.12 Transfer pumps

Transfer pumps are designed with a centrifugal-type pump which use either an electrical motor or a diesel engine as the drive unit. The pumps supply oil to the burner when there is not enough pressure for the well effluent to atomise and burn cleanly through the burner or are used for re-injection of effluent into flowlines after flowing through the production test units. HRS transfer pumps come in various sizes to handle different volumes and pressures. These units have relief valves and bypasses to recirculate fluids if necessary.

The units can be controlled manually, by high/low level switches in the stock tanks, or by means of a level controller and a system of control valves. The units are designed for H2S conditions.

On electrical drive units an outside power source or independent generator which can meet supply requirements of the motor will be required.

3.12.1 Benefit of design principles

3.12.1.1 Electrical drive

·Compact, skid-mounted for handling ease and space saving

·Explosion-proof motor and control box

·Low maintenance-type pump.

3.12.1.2 Diesel engine drive

·Compact, skid-mounted for handling ease and space saving

·Air-start turbo-charged diesel engine

·Low maintenance-type pumps.

3.12.2 Guide to transfer pumps

3.13 Oil and gas manifold

The oil that comes from the separator can be directed through an oil manifold to the gauge tank, surge tank, production flowline or burner depending on the circumstances prevailing during the test. Normally, the manifold consists of 5 inch ´ 2 inch ball valves arranged in such a way that flow from the oil outlet on the separator can be directed to a gauge tank. From the gauge tank, flow is piped to the oil manifold, which is connected to a transfer pump where pressure is boosted so that it can be supplied to a burner or reinjected to a flowline. If a surge tank is used, the manifold serves the same purpose. In effect, it allows the flow from the separator to be directed without interruption to the burner or flowline. For offshore tests, two burners are normally used to allow continual testing irrespective of the prevailing wind direction. The oil manifold also allows the selection of either port or starboard burners without stopping the well test because of undesirable wind directions. The gas manifold can also provide these functions.

3.14 Relief valves and lines

The purpose of the relief valves and lines is to allow well-fluids to vent safely to atmosphere in the event abnormally high pressures are seen in any section of the process train. Abnormally high pressures could exceed the normal working pressure of the equipment and, if not vented safely, would create a catastrophic failure in the system.

Each vent line has a safety relief valve set at a preset pressure (normally equal to, or just less than the working pressure of the system it is protecting). When the line or vessel pressure exceeds this pressure, the valve will open and allow the fluid to be safely vented along the burner boom to the gas flare. It is important to have this line vented to the end of the boom because of the dangers of venting high volumes of potentially toxic gases and flammable gases near the rig. There will not be any valves installed downstream of relief valves to guard against inadvertent closing of one of these, preventing blow down.

Relief lines are proposed in the surface testing layout:

·1,440 psig relief line set between the heater and separator. This line is primarily designed to protect the low pressure coil of the heater and the separator manifold in the event that the well is shut-in at the separator bypass manifold. It will also act as a redundant relief system in the event that the two separator relief valves malfunction. From the relief valve a 4" line will lead the fluid into the HP vent line joining the vent line from the separator.

·Separator relief line designed to protect the separator if pressures exceed the design working pressure of 1,440 psig. Two relief valves are provided and pressure is vented through the 4" HP vent line to the boom.

·Surge tank relief line performs the same function in the lower pressure surge tank. The valve is set at 50 psig and will vent through a line to the boom or overboard.

4" relief lines are recommended on the basis that a reasonable degree of venting capacity is present and yet the lines are easily handled when rigging up the equipment.

Relief lines where possible should be run along the boom so that venting of fluids takes places as far as possible from the rig.

3.15 Booms and burners

Burner booms and burners are mounted on the rig in order to provide a safe means of disposing of hydrocarbons produced during a test. A complete system comprises a number of elements being boom mounting system, boom and burner.

3.15.1 Burner boom

The boom will be designed with the following parameters in mind:

·Heat radiation created by hydrocarbon burning (length).

·Load requirements created by the product lines.

·DyCompanyic requirements as determined by the type of drilling support.

Heat radiation studies can be conducted in order to determine the incidence of heat produced when burning the anticipated amount of hydrocarbons. This may influence the location of the booms and the water screens required to protect vulnerable equipment such as lifeboats, etc.

The load requirements for the booms will be based on the boom supporting the following produced lines:

·1 ´ 6" gas line

·1 ´ 3" oil line

·1 ´ 2" air line

·1 ´ 6" HP vent line

·1 ´ 4" vent line

These lines have been sized according to current well testing practice in order that excessive back pressures are not created when flowing at the design flow rate through any of the lines.

DyCompanyic loading on a boom placed on a semi-submersible rig is greater than for a jack-up rig which does not experience any of the motion associated with yaw, pitch and heave. Therefore care has to be exercised when dealing with both types of support.

The boom is slung from guy lines that are lead up to a king post set on the deck of the drilling rig. Lateral lines prevent any sideways movement of the boom in heavy seas or high winds.

3.15.2 Burners

Multiple headed burners are available that would be sufficient to dispose of the anticipated liquid flow rates. 12,000 bpd of liquid can be atomised at a discharge pressure of 200 psi. Each head is equipped with a 2" atomiser nozzle fitted with an adjustable choke type feature which allows the nozzle size to be adjusted so that optimum atomisation can be achieved. Each head can be isolated so that during periods of lower flowrate a reduced number of heads can be used with each head operating at its optimum efficiency.

The burners can also operate satisfactorily at lower discharge pressure of between 60-70 psi. 4,000 to 6,000 bpd of liquid hydrocarbon can be burnt at these lower pressures.

The burners are equipped with a dual (redundant) air driven magneto ignition system that ignites a propane pilot. The same system is utilised on the gas flare and if necessary on the HP and LP vent lines.

3.15.3 Operation

The oil flows from the separator into the atomiser where the chamber design creates a swirling motion. Then, the oil emerging though the orifice is converted into tiny oil droplets by the turbulence of the compressed air exhaust. Once ignited, the flame is rich and underoxygenated. In the burner, the multiple focused jets of sprayed water (about 6 ft from the burner head) arrive at the flame, where the water is evaporated and water-gas reaction occurs. This reaction prevents the production of carbon black, and the flame burns clear and yellow without fall-out of solid particles of unburnt oil.

When starting up a burner, direction and speed of wind has to be noted and the corresponding boom/burner selected. The sequence of events includes:

·The pilot flame is lit. Compressed air valve is opened.

·Water valve is opened and pressure checked (300 psi maximum). Check that water-spray is evenly distributed.

·Oil production is admitted to burner and ignition occurs. The flame may be 75 to 100 ft long.

Where oil flow is insufficient, the number of burning heads should be reduced until conditions are satisfactory. If, however, the backpressure at the burner is too high for the separator to operate properly, either additional burner heads should be used or the separator pressure should be raised. If neither step is effective, the well needs to be choked back accordingly.

3.15.4 Mud burner

Oil-base muds can be burned by adding diesel oil. For example, for a mud consisting of 40 per cent oil, 27 per cent solids and having a viscosity of 124 cst, it is necessary to dilute with 3 parts diesel to 1 part mud to attain proper burning. With lower viscosities and slightly more oil, the ratio of diesel to mud could be reduced to 1.2. Burning is satisfactory only where oil is the continuous phase in the mud.

In principle, no fall-out is permissible in line with environmental/pollution policies. There may be occasions where well debris, mud, sand, heavy paraffins, or high water/emulsions may cause fall out problems. Enough dispersants should be available on board to handle these unplanned incidents.

3.16 Field laboratory

A field laboratory is generally included as part of the rented test equipment. The laboratory should be located in a safe area and contain the following equipment:

1.A heated calibration bath and deadweight tester to calibrate bottom hole pressure/temperature elements.

2.A centrifuge for determination of sediment and water.

3.Hydrometers and corresponding glassware to determine the specific gravity of the produced crude/water.

4.A gas balance to determine the specific gravity of the gas produced.

5.Viscosity apparatus to determine the viscosity of the oil/condensate produced at 100 and 150 degrees F.

6.Equipment to determine the pour point of the crude/condensate of a fresh wellhead sample.

7.Desk, calculator and typewriter to assist in reporting.

8.Bottom-hole pressure/temperature recorders, clocks, tool, charts, spares, etc.

9.Two bottom hole samplers and equipment to transfer bottom hole samples to special shipping containers. This is in case the service company, owning the field laboratory, takes the bottom hole samples with a sampler run on the piano wire. Otherwise transfer equipment and samples are supplied by the perforating company.

The following equipment is also stored in the laboratory:

1.Pressure gauges, a sufficient number of various ranges.

2.Surface and subsurface temperature/pressure recorders.

3.Orifice plates.

4.Chemical injection pumps (for dehydration, anti-foam and glycol).

5.Special shipping containers for PVT - samples, sample bottles.

6.Small work bench with vice, tools, etc.

7.Spare nipples, elbows, tees, unions, hoses, etc. for hooking-up instruments and connecting flexible piping.

8.U-tube.

9.Deadweight tester for use at the wellhead or flow manifold.

3.16.1 Analysis services

Generally, the mud-logging services company on the drilling rig can supply the following, in addition to their routine services (verification of contract is required):

1.Compositional analysis, resistance and pH of produced water.

2.Approximate analysis of hydrocarbons in produced gas with a gas-chromatograph.

3.CO2 and H2S measurements of the produced gas.

3.17 Emergency shut-down (ESD) systems

ESD systems form an important part of the safety and control of the testing system. The ESD system shown in the layout drawing shows a manual system operating a fail-safe ball valve and an automatic system operating the hydraulically actuated wing valve on the STT.

This system is necessary because:

·Redundancy is built into the system with manual and automatic ESD's operating different valves.

·Automatic system closes the wing valve only, so there is no danger of cutting any wire that may be in the well.

·Simplicity, automatic pilots have been minimised in order to reduce the potential of unnecessary shut-ins through equipment malfunctions.

·Manual system is capable of cutting wire and protects the swivel in the event of failure.

3.17.1 Manual emergency shut-down system

The manual shut-down system comprises the hydraulically actuated lower master valve, a shut-down panel and a number of manually operated pilots. The pilots would be placed as follows:

·Drill floor

·ESD panel

·Separator

·Choke manifold

·Company office

·Helideck

The pilots are connected to a ESD panel by polythene hoses charged with air. Once air pressure is bled from the line the ESD panel will dump hydraulic pressure from the valve control line and the lower master valve will close sealing the ball valve.

The system will take in the order of 10 seconds to close the valve.

The ESD panel should be equipped with a non-return valve so that in the event that supply pressure is lost, the system will not close in the well. Additionally an audible alarm will alert the well testing personnel.

3.17.2 Automatic shut down system

The automatic system will operate the hydraulically actuated wing valve on the flow wing of the STT and comprises an ESD panel, hi-pressure pilot and lo-pressure pilot. The system will work as follows:

·A high pressure pilot (PSH) will be placed in the line between the heater and the separator inlet. The pilot will be set to trip at 1,430 psig and is designed to protect the separator and heater low pressure coil

·A low pressure pilot (PSL) will be placed upstream of the choke manifold and will be set when the well is stable at value consistent with the flowing wellhead pressure. In event that the pressure suddenly drops due to a leak of failure in the line, the pilot will trip.

·An ESD panel will act as the interface between the air lines and the actuator hydraulic line. Once air pressure is lost hydraulic fluid will be dumped to close the valve. Like the manual shut-down panel, the automatic panel will be fitted with a supply non-return and an audible alarm.

·Once hydraulic pressure has been lost to the actuated wing valve, the valve will begin to close. A quick exhaust feature will minimise the closure time so that the well can be shut-in at the gate valve.

Approximately 6 seconds would be required for the system to operate and close the wing valve.

As a general rule, enough time, effort and planning has to be allocated to choice of offshore mobile vessel, well-testing contractor, pre-mobilisation works/checks, etc., before commencement of a test. Pre-hook-ups and testing of rigid flowlines, burners. ESD loops, etc. can radically impact on on-site preparation time, and minimise downtime.

4 Equipment layout

4.1 Surface lay-out

General lay-out and environmental considerations for a safe lay-out of surface testing equipment include:

·Equipment lay-out according to classified area and recommended spacing

·Grounding of units

·Safe and approved electrical connections

·Anchoring of piping and connections

·Colour coding to identify working pressure (WP) and fluids

·Wind directions

·Workplace tidy, clean, not slippery

·Spark-proof hammers

·Safe pressure fittings

·Repair of vessels following standard safety regulations.

Safety standards for equipment on site

Classified zonesOnshoreOffshore

The area around:

Wellhead - Type 245 ft (15 m)30 ft (10 m)

Separators - Type 230 ft (10 m)10 ft (3 m)ª

Gauge tanks - Type 145 ft (15 m)45 ft (15 m)

Outlets of flares, safety valves and vents - Type 145 ft (15 m)45 ft (15 m)

Gas forced heaters and burners must not be used in classified zones.Wireline winches must not be used in classified zones (unless certified).

ª Provided the rupture disc is replaced by a pressure safety valve. Otherwise, the area around the separator is a Type 2 zone within a radius of 45 ft (15 m)

Recommended practices

Installation without a heater: The separator should be located 75 ft (25 m) away from the wellhead. Offshore, this distance may be reduced to 40 ft (13 m). The separator instrument control should be supplied with compressed air. The pressure relief valve must be connected to a safe area.

Tanks equipped with a flame arrestor: The sniffer pipe must be connected to the rig flare. Moreover, manhole cover should be bolted during operation.

In some instances (lack of space), all the recommended distances cannot be respected, however: equipment must never be installed in the classified zones of the wellhead (Type 2 zone) Fired heaters, burners and wireline winches must never be installed in classified zones

5 Wireline equipment

Extensive use is now made of wireline techniques and a variety of wireline equipment and tools are available to perform operations which were previously performed using a well pulling hoist or a drilling unit. Success in performing wireline operations requires personnel with thorough knowledge of equipment/tools and extensive operating experience.

A specialist wireline operator is required with at least 5 years experience, who possesses the knowledge and the ability to "think down-the-hole", while performing demanding physical work during irregular working hours. The service charges for a specialist operator are high ($950/day US). Insufficiently trained or inexperienced wireline operators may make mistakes resulting in many costly rig hours. Company approved supervision is recommended over contractor wireline operators. Wireline equipment for production testing operations is generally rented from the production test contractor.

5.1 Wireline unit

For slickline wireline work, which is normally required during production testing operations, a minimum 40 hp single drum unit with 20,000 ft, 0.092 in. wire is sufficient. The unit should be capable of generating adequate line speed and pull (say 3000 ft/min on full drum at 2000 lb pull). There are wireline packages available consisting of two units i.e. the reel unit and the hydraulic power pack. When the slickline wireline contractor provides the bottom hole pressure and temperature measurement service with surface read-out, he will use a large cabin type wireline unit with the power pack mounted on the same skid. In this case it may be advantageous to have a dual reel unit (electric cable and slickline). However, positioning the unit close to the Xmas tree is not always possible due to its size. To save space it may be more attractive to use the electric cable of the logging contractor. However, this is often much more expensive than using the electric cable from the production wireline contractor. Irrespective of wireline unit chosen, the power pack must be suitable for use in a zone 2 area.

Slickline services may be required whilst testing to assist in Tubing Conveyed Perforating, determine if DST tools are functioning, obtain bottomhole samples and bottomhole pressure information. It would, however, be advantageous in terms of complexity of operations and regard to safety, to limit as much as possible wireline operations in the well.

5.1.1 Types of wires

The types of wire available for use are indicated below. Selection will be influenced by the degree of corrosive elements existing in the well fluid.

Slickline0.092" orSuper 70H2S resistant

0.108"M 35Higher H2S resistance

Braided line3/16"Standard swabline

Monoconductor3/16"Polypropyleneup to 300°F

Tefzel300 to 500°F

It should be noted that the degree of sealing at high pressures on slickline is much greater than a braided line and use of the latter should be avoided.

5.1.2 Wireline unit

5.1.2.1 HP Power Pack Specifications

Engine type4 Cylinder For Type 272275 HP

Safety systemsZone 2 (O.C.M.A. MEC. 1 SPECIFICATION); Inlet and exhaust flame traps ; Over speed shutdown; High Exhaust or water temperature shutdown; Antistatic equipment; Air starter motors

DimensionsLength7 ft 9 ins

Width3 ft 7 in

Height4 ft 3 ins

Weight2,711 lbs

5.1.2.2 Double drum winch specifications

Drum capacitiesUpper drum0.108" slickline24,000 ft

Lower drum3/16" swabline20,000 ft

Optional3/16" Monocond.20,000 ft

Max line speedUpper drumSurface3,200 ft/min

Subsurface1,100 ft/min

Lower drumSurface860 ft/min

Subsurface440 ft/min

Line pullUpper drumSurface4,680 lbs

Subsurface8,000 lbs

Lower drumSurface8,000 lbs

Subsurface10,000 lbs

Power packHydraulic oil42.5 gals/min

DimensionsLength12 ft 4 inch

Width4 ft 7 inch

Height7 ft 4 ins

Weight9,120 lbs

5.2 Pressure control equipment

This comprises the BOP, lubricator and stuffing box and allows surface pressure to be contained when running wireline tools into the well.

When no lubricator valve is used, the lubricator consists of at least two 8 ft sections of appropriate size, a stuffing box for solid wireline ranging from 0.092 in. to 0.108 in. OD wire, and a hydraulically operated BOP. Maximum working pressure should be 5000 psi, 10,000 psi, 15,000 psi and suitable for sour service.

When an electric line is used, a flow tube with grease injection should be used below a hydraulic operating stuffing box. The BOP should be of the twin type with a grease injection port between the rams, the lower rams should be installed upside down to normal to ensure grease retention. Through this port, grease can be injected between the two pairs of closed rams to obtain a gas tight seal around an electric logging, line. Without grease injection, well flow could penetrate the spaces between the individual strands of wire.

5.3 List of wireline tools

A complete list of necessary wireline tools and equipment will be supplied by the production test contractor and will vary depending on the completion to be run. The production test contractor should always be requested to pack the wireline tools in a special tool box so that these cannot be mixed with the other production equipment.

6 Drill stem testing (DST)

6.1 General policy

The following guidelines have been laid down for DST operations. Originally the purpose of DST was to obtain representative formation fluid samples. As such, DST can be defined as the process of allowing an interval to flow into an empty or partly empty drill pipe thereby measuring the downhole pressure. Present day DST operations are often extended, to obtain reservoir data, by flowing the well at surface for prolonged periods. The following guidelines should assist the operator to carry out DST operations safely.

6.2 DST tools on floating rigs

The guidelines for use of DST tools on floating rigs are as follows:

1.Always incorporate a subsurface test-tree (SSTT) so that the well can be closed at sea-bottom level and the flow conduit disconnected. A short SSTT is preferred so that the blind rams of the BOP can be closed above it as a back-up shut-off, independent of the SSTT. A wireline cutting capability should be a design feature of the SSTT selected.

2.The use of accessories which are activated by annulus/tubing pressure has the following advantages:

a)Enables setting and spacing out on floating rigs, especially during rough weather.

b)Eliminates manipulation of the string which may damage the hydraulic lines to the SSTT.

c)Drastically reduces wireline runs, with its inherent risks.

The use of a hydraulic set permanent type packer is recommended. Swabbing in the well when pulling out retrievable packers always exists and therefore a potential danger exists during this operation.

3.The use of a packer in an open hole is not recommended for the following reasons:

a)It is often difficult to obtain a shut-off.

b)It can create all kinds of operational problems such as losses, kicks, getting stuck, caving, plugging or cutting-out of test tools.

c)The increased risk of getting stuck is especially troublesome as a result of the requirement of an SSTT.

4.The use of a tester valve which is operated by manipulating the string is not recommended for the same reasons as in (i) and (ii) of (b). The use of annular pressure operated equipment is recommended instead. There is a wide variety of these equipment and a choice must be made based on objectives.

5.It is recommended that tubing (with metal to metal seals) is used instead of drill pipe when hydrocarbons are expected.

6.3 DST On land and jack-up rigs

The guidelines for use of DST tools on land and jack-up rigs are as follows:

1.Always incorporate in the string at the surface in the vertical run a fail-safe valve so that the well can be closed-in automatically. An actuator with wireline cutting capability should be considered when wireline work is foreseen.

2.Both permanent and retrievable packers may be used. However, the potential danger of swabbing in the well when pulling out retrievable packers must be emphasized.

3.The use of a packer in openhole is not recommended for the same reasons as stated previously.

4.Both mechanically and hydraulically operated tester valves may be used.

5.When hydrocarbons are expected, use tubing (with metal to metal seals) landed in a tubing hanger spool. This restriction will have an influence on the choice of the type of DST tester valve.

In case of exploration wells, when gas composition, GOR, pressures and temperatures are not fully known, the use of tubing suitable for sour service and with metal to metal seals (e.g. Hydril) should be used.

As each Production Test is specific, it is not normal for a COMPANY to have a contract in place such as the one briefly described in the next section. The norm is to enter a short-term contract agreement for a specified number of well tests and equipment and services required to support such an agreement.

Table of Content -  Agreement between COMPANY and CONTRACTOR.

Part 1 - Form of Agreement

Contains contract formalities between parties, timing, laws, type of services etc.

Part 2 - Scope of Work

Outlines object, scope of work and/or services to be provided.

Part 3 - Executive plan

Gives mobilisation/demobilisation plans in timetable form, reports on preparatory arrangements, shipping times etc.

Part 4 - Conditions of Contract

Includes definitions, interpretations, commencement, duration, termination, execution of work and/or services, contractor's personnel, materials tools and equipment, standard of performance, prices and payments, taxes and duties, terms of payments, audit rights of the company, liability for equipment, personnel and operations, insurance, working conditions, special circumstances, sub-contracting, assignment of contract, general provisions, etc.

Part 5 - Provisions by Contractor

Covers supply of equipment and personnel.

Part 6 - Provisions by Company

Same as Part 5 but from the Company's point of responsibility.

Part 7 - Specifications and standards

Lists the requirements that Equipment, Production Testing Operations and Safety considerations must conform to.

Part 8 - Drawings

Appended in this section are drawings of requirements of surface layouts, separators, choke manifolds, test tanks, transfer pumps, booms, burners, laboratories, heaters, pup joints and swivels, gas gravitometers, scanners, deadweight testers, recorders, pumps etc. 

Part 9 - Schedule of prices and rates

This section lists financial considerations such as currency, lump sum payments, day rate payments, volume discounts, reimbursable charges, penalty, liquidated damages, rates for additional work etc.

Part 10 - Administrative procedures

Procedure guides relating to call off, communication, variation to work, invoicing, emergency, incident reporting, subcontracting, completion and close out is covered here.

Part 11 - Performance guarantee

This section requires the contractor to unconditionally and irrevocably guarantee to conform to all proceeding chapters.

"Health, Safety and Environment" are the aspects of activities which relate to how work is carried out rather than to what is done. They have been grouped together and must jointly be given equal priority with the technical content of any operation. This is a Group Policy and it is a primary responsibility of the Drilling Supervisor to ensure that all the contractors involved , as well as all staff members, are aware of this policy and are fully committed to it.
What must be recognised is that health, safety and the protection of the environment are the responsibility of line management and are implicit in all operations, and should not be considered separately.

During Production testing the following general guidelines pertaining to safety should apply.

The appropriate authorities should be notified prior to any production testing especially where it is performed near populated areas. The requirement for such notification is often defined by government legislation.

After perforation, the opening of the well to unload the tubing contents and the initial flow through the separator shall be carried out in daylight. Thereafter the production test may continue during hours of darkness.

The production test (onshore/offshore) should only be commenced under the following conditions:

1.All test facilities are fully pressure tested and checked.

2.Wind force and direction suitable to carry gases away from rig.

3.Fire, H 2S and abandon location drills are held.

4.Weather suitable for rescue operations.

5.Shipping and aircraft warned to stand clear during flaring.

6.Standby boat advised that this operation is to take place, and the action and precautions necessary until the operation is completed.

7.Verify that the wellhead and production valve ESD systems function correctly and that emergency shut-down activating buttons are manned in a safe area throughout the test whilst flowing formation fluids to surface. ESD system checks must be auditable and compliance checked for prior to opening up well.

8.Check that all piping unions are properly matched and according to agreed standardised type.

All hot work shall cease during the production test. Cranes should not be used over or near wirelines, flowlines, separators, heater or choke manifold.

Personnel not directly involved with the operation stay well clear of production lines.

Cooling water hoses shall be laid out on the flare side. In the case that the ambient temperature drops significantly below zero, and icing problems are observed to be occurring as a result of the cooling spray, testing operations should be terminated, possibly being restarted using brine as a cooling fluid. Glycol/water mixture and low freezing point hydraulic fluids should be used in all critical lines/systems. Every measure is to be taken to maintain a safe working environment in the testing area.

Aviation fuel tanks and all pressurised bottles shall be located away from radiant heat and cooled, if required.

A close check should be kept on the casing/tubing annulus pressure. If this pressure increases it should be bled off (noting the volume and type of fluid bled off) and the annulus pressure checked for the rate of build-up. If the annulus pressure cannot be bled off the well shall be squeeze killed or reverse killed, depending on circumstances.

Gas explosion meters, hydrogen sulphide detectors and sets of breathing apparatus must be available. Gas must be checked for the presence of hydrogen sulphide. Contingency plans in the event of significant H2S production must be in place.

Equipment and material to fight oil spills should be available on site in the areas where such spills could give rise to a hazardous situation or have detrimental environmental effects.

After production testing all lines containing oil shall be flushed with water, brine or mud prior to disconnecting.

Rig air for production testing over sustained periods may be insufficient to cope with burner requirements. An independent air supply in this case is preferable.

Install non-return valves in air lines to ensure that rig air systems are not contaminated with hydrocarbons. Do not interconnect air/oil/gas lines.

1. Health hazards from exposure to H2S gas

Refer to EP 55000-32 which comprehensively covers the subject. Other non-H2S related health hazards are documented in EP 55000-31.

2. Area classification

2.1 Hazardous atmosphere

This is an atmosphere containing significant quantities of flammable gas or vapour in a concentration capable of ignition.

The term refers exclusively to the danger arising from ignition, but it must be remembered that a dangerous condition also exists where the atmosphere contains toxic gas or vapour in such a concentration as to be a danger to life.

2.2 Hazardous area

This is an area in which a dangerous atmosphere exists. Dangerous areas are classified under three headings, Zone o, Zone 1, and Zone 2, which are defined as:

Zone 0 An area in which a dangerous atmosphere could continuously be present.

Zone 1 An area in which a dangerous atmosphere is likely to occur under abnormal operating conditions.

Zone 2 An area in which a dangerous atmosphere is likely to occur under normal operating conditions.

Well installations, production, separation units, pumping stations, gas compressor stations and similar installations, including well-pulling and other such well-service operations, should be classified as detailed below.

2.2.1 Zone 1 - Areas

1.An open area within a radius of 15 metres (50 ft) from an open discharge or petroleum-bearing fluid or any other point where emission of a dangerous atmosphere is likely to arise.

2.An area within a radius of 15 metres (50 ft) from well-pulling and other such well-servicing operations unless regular tests with an explosimeter show that no dangerous atmosphere is present in which case this area may be classified as Zone 2.

3.Any enclosed premises containing a source of hazard which may give rise to a dangerous atmosphere under normal operating conditions. The extent of the Zone 1 area should comprise the whole of the premises together with the surrounding area within a radius of 15 metres (50 ft) from any point of exit from the building.

2.2.2 Zone 2 - Areas

1.An area within a radius of 7.5 metres (25 ft) of any production plant or other oil process installation in open premises or in the open air, operated as a closed system to prevent in normal circumstances the emission or accumulation in the area of a dangerous atmosphere.

2.Any enclosed premises containing a source of hazard which may give rise to a dangerous atmosphere under abnormal operating conditions. The interior of the building should be classified as Zone 1 but the surrounding area in the open air within a radius of 7.5 metres (25 ft) from any point of exit from the premises may be classified as Zone 2.

3.Any enclosed premises not containing a source of hazard but located in a Zone 2 area should be classified as Zone 1 but if the entry of a dangerous atmosphere is continuously prevented by the provision of fire walls, ventilation or other means, the premises may be classified as a safe area. When mechanical ventilation is employed and it is not possible to guarantee the source and reliability of a safe atmosphere, the premises should be classified as Zone 2.

2.2.3 Vertical extent of Zone 1 and Zone 1 areas

In the naturally well-ventilated conditions of operation on offshore wellhead structures, the vertical extent of the dangerous area above the highest source of hazard may be reduced to 3 metres (10 ft) over the whole of the classified area. Below the source of hazard, the dangerous area extends down to the surface of the water unless there are effective means of preventing the movement or accumulation of oil or gas.

If lighter-than-air gas is released, due consideration must be given to the vertical extent if there is an obstruction to gas dispersal (such as an heliport deck).

3. Pressure testing

Before installation all equipment must be satisfactorily pressure tested to the maximum allowable working pressure in accordance with API spec 6A Appendix F. The following are particularly important:

1.The X-mas tree should be pressure-tested on site. Each valve of the X-mas tree and the check valve should be tested individually.

2.The steamlines to the heat exchanger of the test equipment should be pressure-tested.

3.The relief valves of the separator should be popped when pressure testing the separator. After the test the data and pop pressure should be painted on the relief valve.

4.The SSTT-tree and lubricator valve should be pressure-tested and function-tested on deck before installation in the well.

4. Preparatory work

Whether the drillpipe should remain in stands in the derrick during the test should be considered. A potential danger with drillpipe in the derrick during production test operations is that, in case of a fire on the drill floor the derrick structure is weakened which may cause drillpipe to fall out of the derrick. a further cause for concern is the movement of drillpipe in periods of high wind. A suitable platform should be available to enable safe working at the level of the X-mas tree.

5. Killing facilities

Adequate killing fluid of the correct gradient should be available. Kill/mud pumps should be connected to the kill mud tanks with a control switch on the rig floor to the pump room. Killing lines from the kill/mud pumps to the Xmas tree/annulus should be as direct as possible. All valves in the killing system should be trimmed and the non-return valve at the Xmas tree checked to ensure it is not leaking. A circulating/kill valve with a suitable tubing thread pin end on bottom should be on the drill-floor throughout the test so that shutting off or circulating the well during pulling the tubing is possible.

6. Hot work

Hot work during production testing operations may only take place when authorised by a "Hot Work Permit", which is signed by both the person in charge of the rig and the Production Operations Engineer. A permit to work system exists for the various facets of rig operations and must be utilised.

7. Perforating - safety regulations

The following safety regulations must be observed during perforating:

1.All personnel non-essential to perforating and production testing should be taken off the rig prior to perforating the well.

2.During any job involving the use of explosives, the number of personnel employed should be kept to a minimum. All other persons should be excluded from the danger area (e.g. walk-way, derrick floor) throughout the operation.

3.Warning signs should be placed on access routes to danger areas.

4.An Abandon Rig, Blow-out and Fire Drill should be held prior to perforating operations.

5.During perforating operations, the fire-fighting system should be under pressure.

6.Work involving the use of explosives should never be done under conditions of thunder, lightning or heavy fog.

7.Welding is not permitted during the period commencing with the arming of the gun and finishing with the confirmation of no misfire after the removal of the gun from the lubricator.

8.Gas explosion meters, hydrogen sulphide detector(s) and portable breathing apparatus sets must be available and operable. As soon as possible well effluents must be checked for the presence of hydrogen sulphide by the Production Operations Engineer or Petroleum Engineer.

9.No helicopter landings can be made from the time the gun is armed until the gun has been pulled and checked or disarmed.

10.The first perforation must be carried out in daylight, but later runs may be carried out at night. However, if in the course of perforating or during subsequent production testing the well has to be killed, the first of any subsequent perforations must also be carried out in daylight.

11.Before the gun is armed all transmitters including the radio beacon (the teleprinter may be left on stand-by), cranes, welding machines, etc. in the immediate vicinity (within a radius of 150 ft) of the wellhead must be switched off and remain switched off until the gun has been pulled, laid down and checked/disarmed. Transmission, crane operations, etc. may be resumed thereafter. Supply boats or other vessels should not be moored to the rig and should be ordered to "standoff" during these operations.

12.Portable transmitters should be placed in one room to prevent accidental transmission.

13.The Petroleum Engineer is to witness the earth testing of equipment. A constant check to ensure that voltage does not exist between the casing and rig at surface must be made. If a voltage is found to exist, all sources of electrical energy must be switched off (this may preclude perforating at night).

14.Before the well is perforated a Safety meeting should be held with the following people present:

-Drilling Supervisor

-Petroleum Engineer

-Rig Drilling Supervisor

-Barge Engineer

-Radio Operator

-Production test contractors

-Perforating contractor.

During this meeting the Company Production Operations Engineer should explain the safety regulations. He should also emphasise responsibilities and outline reporting/communication lines which have to be followed.

15.Two hours before each perforating run the Petroleum Engineer must inform the base about the estimated time of closing down the radio beacon transmitters and other means of communication, and the duration of the shut-down. Actual times will be advised by the radio operator. Helicopter flight control must receive the message of closing down communication in order to postpone any planned flights.

16.The Production Operations Engineer should be on the site during perforating operations. He will ensure that the THP is bled down to zero and that the well is closed in.

8. Chemicals (SHOC)

Reference should be made to Safe Handling of Chemicals which should lists the chemicals commonly used in the petroleum industry and gives details of its composition, health considerations when handling, inhaling, etc.

1. Objective:

DST the 14,000’ sand to evaluate production potential.

2. Well Information

Water Depth: 130’
RKB to WL: 90’
RKB to ML: 220’

MW Drilled With: 17.0 ppg
TD: 14,150’MD/TVD
PBTD: ±13,960’ MD/TVD

Directional Information Vertical Well

Casing Size: 26”, 202 ppf , Gr B at 470’ MD/TVD
Casing Size: 18 5/8” 87.5# J-55 BTC at 745’ MD/TVD
Casing Size: 13-3/8” 68# J-55 BTC at 3,531’ MD/TVD
Casing Size: 9-5/8” 53.5# HCQ-125 ANJO at 12,643’ MD/TVD
Casing Size: 7” 32# Q-125 ANJO at 14,050’ MD/TVD

3. Zone of Interest

Sand 14,000’ Sand

MD Perforations: 13,834’ – 13,860’
TVD Perforations 13,834’ – 13,860’

Number of JSPF: 12
Max Deviation: 2.5 at 13,862’
Estimated BHP: 11,332 psi (15.7 ppg)
Estimated BHT: ± 248° F
Estimated SITP: ± 6,280psi

Completion Fluid: 16.5ppg WBM

4. Vendor List:

5. Casing Information

Capacity Casing Strength
Size BBL/LF LF/BBL ID Drift Collapse Burst
9-5/8” 53.5 ppf 0.0707 14.13 8.535 8.500 8,850 12,390
7” 32.0 ppf 0.0360 27.72 6.094
5.969 11,720 14,160

6. Drills and Tests

1. Test BOP’s every fourteen (14) days to 250 psi low and 10,000 psi high. Test annular to 250 psi low and 3,500 psi high. Function test all rams once every seven (7) days alternating between stations and record on IADC report.
2. A Well-Control Drill will be performed at least once a week with each crew as per regulatory requirements and recorded on the IADC reports.
3. Abandon Ship and Fire Drills will be performed weekly as per Coast Guard Regulations.
4. EPA compliance with effluent limitations and monitoring requirements will be performed as per the “NPDES” permit.

7. Procedure

Run Liner and prepare for DST
1. Make up BHA for conditioning trip and TIH. Circulate and condition mud until the hole is free of cuttings and gas. Insure Yp is within range or slightly lower. POOH to run 7” production liner.

2. RU casing tools and run 7” 32 ppf Q-125 ANJO liner, running tool, hanger, and liner top packer with two joints between float shoe and float collar; and, one joint between float collar and landing collar. Run bow spring centralizers/turbolizers on bottom three joints; two per joint across all prospective zones; and one every other joint to the 9-5/8” shoe. Total 20 centralizers. Space out for hanger to be 400’ to 500’ above 9-5/8” shoe, or as required for completion objectives.
Note: Run a high-flow bypass tool from the Liner Hanger Company

3. Run liner to bottom on drill pipe washing down last stand. Circulate bottoms up, drop ball and set liner hanger. Release running tool and set back down to confirm hanger is set.

4. MU cementing head, test surface lines and cement liner as follows (cement to have zero free water):

a. Pump 35 bbl Mud Push II Spacer mixed at 17.00 ppg (mixed with fresh water)
b. Tail: 476 sx Premium cement Class “H” + 0.02 gps D047 (Antifoam Agent) + 0.30 gps D-168 (Uniflac-L) + 0.04 gps B158A (Viscous Liquid Suspension) + 0.08 gps D197 (AccuSET Retarder) + 0.02 gps D080 (Cement Liquid Dispersant) + D030 (Silica Cement) equal to 35% BWOB

Slurry Weight: 17.5 ppg
Slurry Yield: 1.24 ft3/sack
Water Ratio: 3.78 gal/sack (fresh water)

(Cement volume calculated to bring TOC to TOL at 12,300’ MD, 300’ lap, with 25% open hole excess. Volume to be adjusted for actual hole condition)
Note: Have samples of mix water and cement tested prior to job to confirm pumping times and catch two samples of slurry.

5. Bump plug with 1000 psi over cementing pressure. Do not over displace by more than half the shoe track volume.

6. PU and set back down to set liner top packer. Reverse out cement and contaminated mud at TOL.

7. Close annular and test liner top packer/casing to 1,220 psi. POOH.

8. Change upper rams to 3-1/2” x 5” flex rams. Test rams to 250 psi low and 10,000 psi high on the 5” and 3-1/2”. Test annular to 250 psi low and 3,500 psi high on the 5” and 3-1/2”.

9. RU e-line and run GR-CCL with junk basket/gauge ring to PBTD. Confirm PBTD depth to be used for TCP space out. Have a casing scraper available should the gauge ring hang up.

Run TCP assembly and perforate

10. MU 4-12” 12 spf TCP/packer assembly in accordance with diagram.

11. RIH on drill pipe with 18 x 5” drill collars. Lightly tag PBTD and pick up to perforating depth. Set packer at 13,585’. Test backside to 1,000psi.

12. RU 3” 10,000psi well test equipment and StricLan test tree.
Note: Have a minimum of 2 x 210 bbls stock tanks and sufficient NPT tanks to transport 2,000 bbls of liquid.

13. RU surface test equipment. Hold a pre-job safety meeting and test surface lines and equipment to 10,000psi. Install Wellhead monitoring systems on well testers manifold. RU e-line and SRO gauges.

14. Displace drill pipe with seawater to within 5 bbls of the bypass. Close bypass and bleed tubing pressure to 3,550 psi (which equates to 1,500psi underbalance). Pressure up on annulus to 1,000 psi.

15. Pressure up on drill pipe to 7,500psi and hold for 2 minutes to initiate TCP firing sequence (Firing delay is 10 minutes). Bleed off test string pressure to 4,250 psi to achieve 800psi underbalance when guns fire.

Flow well

16. After guns fire, open well to flow initially on a 6/64 choke. Continue flowing at 300-to-500 bpd rate until all seawater and drilling mud has been unloaded and flow rate has stabilized at unloading velocity.

17. RIH logging during the later stage of the initial clean up period with SRO pressure & temperature tools, to 13,950 ft MD. DO NOT EXCEED 100 FT PER MINUTE while RIH.

18. Perform pressure/temp flowing profile across perforated interval up and down (13,950’ MD to 13,800’ MD) at 30 ft/min.

19. POOH to Mid Perfs @ 13,847’ MD and flow well for thirty minutes at test rate (or until well has cleaned up as per the Altec Engineer).

20. Collect all the well test data as follows.
Total Fluid in bbls/day Choke size in xx/64ths
Total Gas Rate in mscf/day Oil/gas gravity
Test Separator Temperature Casing Pressure in psi
Test Separator Pressure Water cut in %
Flowing Tubing Pressure Fluid/Gas properties

21. Shut in the well for initial build-up (+2 to +12) hours. Close the wing valve and the header valve.
THERE MUST BE NO LEAKS.
Continue to monitor surface pressures (tubing). All data will be sent to Altec Office prior to proceeding to next step

22. RIH to 13,950’ MD and repeat step five making static pass across the perforated interval.

23. POOH to Mid Perfs @ 13,847’ MD and open well to flow on a fixed choke based upon initial flow period @ +500 BOPD. Duration of flow will be determined by Altec Engineer.
Estimated stabilized flow time of two days with subsequent shut-in should be adequate. All decisions will be made in real time as to rate and duration based upon data acquired.

24. RIH to 13,950’ MD and repeat step five making flowing pass across the perforated interval.

25. POOH to Mid Perfs @ 13,847’ MD and flow well for one hour at test rate.

26. Collect all the well test data as follows for the extended flow period.
Total Fluid in bbls/day Choke size in xx/64ths
Total Gas Rate in mscf/day Oil/gas gravity
Test Separator Temperature Casing Pressure in psi
Test Separator Pressure Water cut in %
Flowing Tubing Pressure Fluid/Gas properties

Note: During final flow period, obtain duplicate samples of gas, condensate and water for laboratory analysis. Monitor and record pressures and produced gas and liquids. Have 5 gallon oil sample containers for cold finger test.

27. Shut in the well for +12 to +48 hours (depending on surface readout data). Close the wing valve and the header valve.
THERE MUST BE NO LEAKS.
Continue to monitor surface pressures (tubing).
All data will be sent to Altec Office prior to proceeding to next step

28. RIH to 13,950’ MD and repeat step five making static pass across the perforated interval.

29. POOH with test string obtaining static logging pass to surface (100 fpm)

30. RD e-line and download tools.

31. Open bypass and reverse out produced fluids at least two test string volumes with 16.5 ppg mud.

32. Check for losses and spot LCM pill if losses exceed 10 bbl/hr. Release packer and pick up above perforations and monitor well. POOH with test string and lay down TCP tools.

33. A separate procedure will be provided for suspension or P&A. Have a 7” retainer on board if well is to be plugged.

34. Perform Soil Boring procedures if the well is to be suspended at the mudline.

8. Morning Reports:

Fax in daily operations reports, cost sheets, fluid reports, test reports, Monthly DMR reports, end of well transfers, and well schematics to:

9. Support Staff: