11. Well Testing - Test String Programme Example

*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: