Appendix 5. Well Test Program

  • Resource Company Name
  • Field Name
  • Well Name
  • Document Number
  • Revision Number
Table Review & Approval
Name Position Signature Date
Author Well Test Engineer    
Review Sub surface Engineer    
Review Drilling Supervisor    
Approval Drilling Department Manager    
Table Distribution
Name Position Type Hard Copies Qty
Name 1 Drilling Department Manager Hard & Soft 1 copy
Name 2 Subsurface Manager Hard & Soft 1 copy
Name 3 Well Test Engineer Hard & Soft 1 copy
Name 4 Offshore Drilling Supervisor Soft  
Name 5 Well Test Contractor Focal Points Soft  
Name 6 Wellsite distribution Hard 10 Copies
File Document Control Soft  

References

  1. Well Test Personnel Roles and Responsibilities
  2. Wellsite Well Test Equipment Preparation Checklist
  3. Pressure Test Guideline
  4. Facility Safety Management Systems
  5. Contractor Procedures

  1. Overview 287
    1. Purpose 287
    2. Management of Change 287
    3. Well and Reservoir Data 287
    4. Technical Objectives 288
    5. Assumptions 289
    6. Roles and Responsibilities 289
    7. Test Outline 289
  2. Preparations 289
    1. All Contractors 289
    2. TCP Preparations 290
    3. DST Preparations 290
    4. Tubing Preparations 290
    5. Tubing Handling Equipment 290
    6. Subsea Preparations 290
    7. Surface Equipment Preparations 291
    8. Data Acquisition Preparations 291
    9. Slickline Preparations 291
    10. Fishing Equipment 292
    11. Well Test Engineer 292
  3. Critical Path Procedures 292
    1. Pre Assemblies 292
    2. Packer Installation 292
    3. Test String Installation 292
    4. Commissioning & Underbalance 294
    5. Perforation 294
    6. Clean Up & Flow 295
    7. Well Kill & Test String Retrieval 295
  4. Test outline and Time Estimate 296
  5. Appendix A Contingency Procedures 297
    1. Tubing Leak – Contingencies 297
    2. TCP Misfire 298
    3. Emergency Disconnect – Recommended 298
    4. Emergency Disconnect – Insufficient time to Bullhead 299
    5. Emergency Disconnect – Immediate Disconnect 299
  6. Appendix B Casing and Tubing Data 299
  7. Appendix C Layout Drawing 299
  8. Appendix D P & ID 299

1.0.. Overview

1.1. Purpose

The purpose of this program is to ensure that the planning decisions regarding the conduct of the well test are properly implemented. This program is intended as the principal reference for the conduct of the well test operation; it contains the procedures required for the wellsite execution of the well test and also includes references to contractor procedures which relate to the operation or handling of contractor specific equipment.

1.2. Management of Change

Deviations to the procedures in this program are subject to management of change controls. The Drilling Supervisor together with the Well Test Engineer will assess each change in order to determine if it requires written approval from head office. Small changes which do not entail significant safety or operational risks may be made with the authority of the Drilling supervisor and the Well Test Engineer provided such changes are subject to risk assessment.

Table Well and Reservoir Data
Well & Facility
Well Name Insert wellname
Well Type Vertical Exploration
Permit Insert permit licence number
Drilling Contractor Insert drilling facility company name
Drilling Rig Insert drilling facility name
Depth Data
Reference RT (Rotary table)
Depth measurements m MD RT (Unless stated otherwise)
RT Elevation LAT 25m
Water Depth m LAT 300m
Deviation Nil
Test Formation Insert formation name
Total Depth (TD) 2500 m
Perforation Interval 2420 to 2450 m
Well Conditions
Max BHP at TD 3600 psi
Max BHT at TD 120 Celsius
Max SITHP 3500 psi
Max THT 60 Celsius
Max Mudline Temp 80 Celsius
Reservoir Data
Lithology Sandstone
Porosity 10%
Permeability 10 mD
Reservoir fluid Gas
CGR 9 STB/MMSCF
GWC 2500 m MD RT
Pressure Regime Normally pressured
Casing & Tubing
Production String Tubing Nominal 4 ½”, 15.5# L80 PH6
Landing String Tubing Nominal 4 ½”, 15.5# L80 PH6
Production Casing Data 9 5/8” 47 ppf L80 Vam Top
Production Liner Data 7”, 29 ppf L80 Vam Top
Casing Test Pressure 5,000 psi
Fluids
Drill Fluid SBM Synthetic Based Mud
Completion Fluid Type NaCl Brine
Completion Fluid Weight ~9.0 ppg
Underbalance Fluid Diesel
Underbalance Achievable ~700 psi
Test fluid Gas
Gas SG (Air=1) 0.8
H2S <10 ppm
CO2 <3%
Sand Not expected
Emulsions/Wax N/A
Hydrates Possible – have occurred in offset wells
Estimated Pour Point N/A
Test Chemicals Methanol, Glycol
Overpressure ~200 psi (Prior to underbalance fluid)
Well Suspension P/A
Production
Maximum expected flowrate 60 MMSCFD
Duration 24 hours

1.4. Technical Objectives

  1. Determine key reservoir parameters (k, skin, D, etc)
  2. Determine well deliverability and PI
  3. Determine the liquid yields or CGR
  4. Determine initial Reservoir Pressure (Pi)
  5. Obtain representative gas samples for PVT analysis

1.5. Assumptions

  1. A pip tag and pup joint have been included in the 7” liner and located approximately 100 m above the top of the formation sand.
  2. The BOP has been pressure tested prior to the operation
  3. The lower and middle rams are configured for 5”
  4. The 7” 29 ppf liner has been cemented and pressure tested to 5,000 psi
  5. Setting depths are as per the Basis For Design.
  6. The 9 5/8” Wear bushing has been installed
  7. A 7” Casing scraper has been run across the packer setting depths
  8. The drilling mud has been displaced to 9 ppg brine at the end of the casing scraper run.
  9. A cement bond log has been run and depths to the formation confirmed

1.6. Roles and Responsibilities

The roles and responsibilities for personnel involved with the well test are detailed in a separate controlled document Well Test Operation Personnel Roles and Responsibilities.

1.7. Test Outline

A permanent seal bore packer shall be installed on wireline approximately 50 m above the top of the formation sand and set inside the 7” liner.

3 3/8” TCP guns shall be fitted below a packer stinger and conveyed along with DST tools on 4 ½” PH6 15.5 ppf tubing. The stinger shall be set in compression to eliminate gauge movement due to expansion.

A diesel cushion fluid shall be used to provide an underbalance and the guns shall be activated hydraulically with surface applied pressure.

All produced fluids shall be disposed of at the flare. Metering and sampling shall take place from a test separator.

2.0. Preparations

2.1. All Contractors

  • Perform inventory checks on all equipment
  • Inspect equipment for transport damage
  • Report to the Well Test Engineer
  • Any contractor performing hazardous activities such as pressure testing, working at heights, electrical work, and handling of dangerous goods must comply with the safety management systems, permits, JSA etc.
  • All pressure test charts must be provided to the Well Test Engineer, each chart clearly labelled.

2.2. TCP Preparations

  • Determine required perforation interval from Well Test Engineer
  • Load guns in accordance with contractor specific handling procedures and with the facility safety management systems.
  • Strap guns on deck and number each item in order of its installation. Measurements must be witnessed by the Well Test Engineer.
  • Confirm well conditions and perform firing head calculations, provide calculations to the Well Test Engineer
  • Prepare sub assembly drawings showing dimensions and TCP firing head settings.

2.3.. DST Preparations

  • Confirm well conditions and required operating settings for tools.
  • Pressure test tools & assemblies on deck as per contractor test procedures to the general test pressure, record all tests on a chart
  • Well Test Engineer to witness the installation of rupture discs and shear pins.
  • Review string movement calculations to ensure correct packer weight or packer seal bore spaceout
  • Prepare sub assembly drawings with dimensions and tool settings

2.4. Tubing Preparations

  • Layout, clean and inspect tubing and pup joint end connections, drift all tubulars.
  • Strap (measure) each joint, use overall length dimensions only, made up lengths will be subtracted in the tally, paint length and number on each joint.
  • Prepare a tubing tally with all tubing lengths and numbers
  • Include space out pups
  • Remove end protectors, clean and inspect threads in preparation for running

2.5. Tubing Handling Equipment

  • Function test tongs and power pack on deck
  • Function test make-up computer and ensure correct tubing torque settings are programmed
  • Check tubing dies are the correct size and type for the test tubing
  • Ensure back-up equipment is to hand should it be required

2.6. Subsea Preparations

  • Prepare an assembly drawing showing the spaceout of the Subsea test tree inside the BOP. Include all relevant dimensions.
  • Function and pressure test the subsea test tree and lubricator valves on deck. Function testing should include the full length umbilicals for each valve.
  • Confirm umbilical length is appropriate for installation
  • Install a full single joint of tubing and short saver pup below the flowhead
  • Make up SSTT sub assembly with a 2 m handling pup above and a short saver pup below
  • The Well Test Engineer will witness all assemblies strapped
  • Prepare sub assembly drawings with dimensions and provide same to the Well Test Engineer.

2.7. Surface Equipment Preparations

  • Surface equipment laid out and assembled in accordance with the layout and P & ID drawings.
  • Confirm relief valves and automatic shutdown switches are situated in accordance with the P & ID and that the settings and calibrations are correct.
  • Review pressure test procedure with Well Test Engineer, pressure test surface equipment as per contractor procedures and in accordance with the facility safety management systems, permits, JSA etc.
  • Function test the boiler, compressors and burner head ignition system.

2.8. Data Acquisition Preparations

  • Confirm type and number of gauges supplied are as per program
  • Confirm gauge calibrations are current
  • Confirm gauges are function and pressure tested on deck
  • Confirm gauges are setup as specified in the program or as directed by the Well Test Engineer.
  • Confirm a new battery is installed into each gauge and that each battery has been checked.

2.9. Slickline Preparations

  • Assemble pressure control equipment and pressure test as per contractor procedures and in accordance with the facility safety management systems permit, JSA etc.
  • Function test winch unit and power pack.
  • Inspect wire drum and perform torsion tests on wire.
  • Inspect weight indicator and depth counter
  • Function test air winch for handling pressure control equipment
  • Prepare a pressure control equipment assembly drawing including dimensions to confirm adequate height available for installation.
  • Prepare string diagrams for all potential operations.

2.10. Fishing Equipment

  • Review inventory of fishing equipment supplied matches the range of equipment to be installed in the test string
  • Ensure specialised fishing equipment supplied separately is available. e.g. subsea fishing equipment

2.11. Well Test Engineer

  • Complete wellsite Well Test Equipment Preparation Checklist
  • Prepare Running Tally

3.0. Critical Path Procedures

3.1. Pre Assemblies

  1. Conduct JSA – handling pre-assemblies
  2. Clear drill floor of unnecessary equipment
  3. Change handling gear to 5” Drill Pipe for flowhead
  4. Pick up tubing handling equipment
  5. Pick up flowhead assembly and make up as directed by the subsea contractor supervisor
  6. Lay out flowhead
  7. Pick up SSTT assembly and make up as directed by the subsea contractor supervisor

3.2. Packer Installation

  1. Conduct JSA – Wireline operations
  2. Pick up the packer body assembly fitted to the wireline as directed by the packer specialist
  3. RIH with packer body assembly on wireline to approximately 20 m below the proposed setting depth
  4. Correlate packer setting depth against the casing pip tag
  5. Set packer on depth as directed by the Well Test Engineer
  6. POOH with wireline & packer setting tool

3.3. Test String Installation

  1. Conduct JSA – TCP Guns & Tubing handling
    • Ensure well control crossovers are available on the drill floor and connected to the TIW valve
  2. Pick up TCP Guns and accessories as per the running tally and make up as directed by the TCP specialist
  3. Pick up packer locator and make up to top of TCP gun assembly as directed by the packer specialist
  4. Pick up DST tools and assemblies as per the running tally and make up as directed by the DST tools specialist
    • Running speed should not exceed the equivalent of 90 secs per stand
    • Set slips softly
    • Engage compensators as packer passes the BOP and wellhead
  5. Pick up the first 3 joints of 4 ½” PH6 15.5 ppf tubing, install crossover to drill pipe and pressure test BHA to 5000 psi as per the pressure test guideline
  6. Continue to RIH with 4 ½” PH6 15.5 ppf tubing as per running tally
    • Engage compensators as packer enters the liner
    • In the event the string hangs up, call the Well Test Engineer immediately
  7. Install crossover to drill pipe as indicated on the tally where it is intended to install the SSTT, continue to RIH with 5” drill pipe
    • Ensure first joint of pipe is painted white
  8. Engage compensators as the TCP guns enter the seal bore packer
  9. Perform pick up and slack off weight checks
  10. Continue to RIH with test string note any weight loss corresponding to packer seals entering the packer body
  11. Land off with 10,000 lbs slack off weight to ensure locator has fully landed out
  12. Crosscheck depth against running tally
  13. Pick up and repeat the above land off to confirm spaceout
  14. Pick up to spaceout locator as required and mark the pipe at the rotary table
  15. Close pipe rams on painted joint
  16. Open pipe rams and POOH to top of tubing
    • Measure the distance from the ram marks to the top of the tubing measurement A
    • Subtract the length of the SSTT assembly from the mid point of the slick joint to the bottom of the assembly measurement B
  17. Install spaceout pup joints to make up the difference between A & B
    • It is recommended to install the pup joints below a full joint to facilitate variable ram closure when the string is later retrieved
  18. Conduct JSA – Landing string installation
  19. Pick up and install the SSTT assembly as directed by the Subsea Specialist
  20. Attach umbilicals and secure umbilicals to tubing with clamps or tape as pre-arranged
  21. Continue to RIH with 4 ½” PH6 15.5 ppf tubing as per running tally
  22. Pick up and install the lubricator valve assembly as directed by the Subsea Specialist
  23. Conduct JSA – Flowhead Installation
  24. Install top drive sub and slickline air winch
  25. Install extended bail arms shackled to the drilling bails using 85 t shackles
  26. Install 5” drill pipe elevators
  27. Pick up flowhead and make up as directed by the subsea specialist
  28. Install control lines, crossovers and high pressure flexible hoses
  29. Pressure test the test string, flowhead and surface lines as per pressure test program
  30. Perform pick up and slack off weight checks
  31. Engage compensators
  32. Ensure production valve on flowhead is open to the well test package
    • This step ensures that a hydraulic lock does not occur when the locator seals enter the packer body
  33. Land off at wellhead
  34. Retain flowhead and landing string weight with blocks

3.4. Commissioning & Underbalance

  1. Conduct – JSA pressure testing and diesel pumping operations
  2. Close pipe rams
  3. Pressure annulus from cement unit to 1000 psi this will lock open the flapper, and activate the tester valve reference tool and will also test the packer seal
  4. Cycle the re-closable circulating valve to the open position
  5. Displace diesel to the test string
    • The volume displaced will be equivalent to the test string volume to the circulating valve less 5 bbls
    • This will provide an underbalance pressure of ~700 psi
  6. Close circulating valve
  7. Function test ESD system

3.5. Perforation

  1. Conduct Pre Test Safety Meeting – Refer to Wellsite Well Test Preparation Checklist
  2. Apply pressure to annulus to open the tester valve
    • Note the volumes pumped to achieve activation pressure
  3. Pressure tubing to calculated TCP activation pressure and hold as directed by TCP specialist
  4. Bleed off pressure to 50 psi at surface and monitor at choke manifold
    • TCP firing head is fitted with a delay which activates the guns ~15 mins after pressure hs been removed

3.6. Clean Up & Flow

  1. Once a positive indication that the guns have fired has been observed, open the well on a ¼” adjustable choke to the surge tank and continue flowing for 10 mins
  2. Bleed off at annulus to close the tester valve downhole, when a pressure drop is observed at surface close the choke manifold
  3. Remain shut in for 30 mins or as directed by the Well Test Engineer
  4. Ensure the boiler is running prior to the clean up flow
  5. Pressure annulus to open the tester valve, when a pressure increase is observed at surface, open the choke manifold on a ¼” adjustable choke to the surge tank
  6. Continue to increase the choke as directed by the Well Test Engineer or as dictated by the operational need to allow the well to clean up
  7. Direct flow to the burners once a sufficient wellhead pressure is available to ensure a good burn
  8. Increase choke to the maximum rate to achieve the best possible clean up. Inject methanol as required to manage hydrates
    • Switch to a fixed choke when conditions have stabilised
    • Record the estimated flow rate as the choke is increased during the clean up
  9. Monitor fluids during the clean up, when the clean up criteria have been met, the 1st main flow period shall commence
    • Clean up criteria are 3 successive BSW measurements <1% & stable wellhead pressure
    • Direct flow through separator for main flow periods
    • Take samples as required according to the sampling programme
  10. After 4 hours reduce to a fixed choke to provide an intermediate flow rate as specified by the Well Test Engineer
    • Take samples as required according to the sampling programme
  11. After 4 hours reduce to a fixed choke to provide the lowest flow rate as specified by the Well Test Engineer
    • Take samples as required according to the sampling programme
  12. After 4 hours, increase the choke to the maximum rate to achieve maximum drawdown prior to shut in
  13. After 4 hours, bleed off annulus pressure to close tester valve, when a pressure drop is observed at surface, close the choke manifold
  14. Remain shut in for 24 hours or as directed by the Well Test Engineer

3.7. Well Kill & Test String Retrieval

  1. At the end of the build up period, open the choke manifold and bleed surface pressure to 0 psi
  2. Lubricate 9.0 ppg KCL brine into the string through the kill valve of the flowhead using the cement unit to fill the test string
  3. Pressure annulus to open the tester valve
  4. Bullhead 9.0 ppg KCL brine into the formation, pump at least the volume from the tester valve to the perforations or until a sharp rise in pressure indicates the brine fluid has reached the formation
  5. Flow check for 15 minutes
  6. Cycle the tester valve to the lock open position
  7. Open pipe rams & pick up on flowhead to un-sting from the packer
  8. Circulate 1.5 hole volumes of 9.0 ppg KCL brine using the mud pumps
  9. Flow check for 15 minutes
  10. Conduct JSA – Flowhead removal
  11. Break out the surface lines and the flowhead
  12. Remove extended bails
  13. Prepare tubing handling equipment
  14. Commence POOH with tubing lay out joints
  15. Layout SSTT assembly to be picked up later for break out
  16. Continue POOH with test string
    • Ensure TCP, DST, Subsea and Packer specialists are present on the drill floor as their respective tools reach surface
  17. End of program, refer to Drilling Program for P & A procedures

Table Test outline and Time Estimate
Step Description Hours
1. Well Preparation  
1.1 Run and cement 7” Liner 24
1.2 RIH with bit and scraper 6
1.3 Work scraper over packer setting depths 1
1.4 Circulate to clean well and pump brine, POOH bit & scraper 8
1.5 Run CBL & GR & Gauge ring 3
1.6 BOP Test 6
Total Well Preparation Time 48
2. Install Test String  
2.1 Make up pre-assemblies 2
2.2 RIH with Permanent Packer body, set packer in 7” liner 4
2.3 Make up 3 3/8” TCP gun assembly 2
2.4 Make up DST sub assemblies 4
2.5 Pressure test BHA 1
2.6 RIH on 4-1/2” 15.5 ppf PH6 tubing 15
2.7 Crossover to drill pipe & continue to RIH 3
2.8 Land off locator inside packer & close pipe rams 1
2.9 POOH to top of tubing & space out with pup joints as required 3
2.10 Install subsea test tree 1
2.11 RIH 4 ½” 15.5 ppf PH6 Landing string 4
2.12 Install Flowhead, surface lines & pressure test 3
2.13 Land off inside packer 1
2.14 Circulate diesel underbalance 3
2.15 Pressure test annulus and cycle tools to test position. 1
2.16 Hold rig floor safety meeting. Function test ESD system 1
Total Install Test String Time 49
3. Well Test Production  
3.1 Perforate well. Perform initial flow & build up 1
3.2 Clean up flow period 3
3.3 Main flow high rate 4
3.4 Main flow intermediate flow rate 4
3.5 Main flow low flow rate 4
3.6 Main flow maximum flow rate 4
3.7 Main Shut in period 24
Total Well Test Production Time 44
4. Kill Well and Retrieve Test String  
4.1 Lubricate kill fluid and bullhead kill 2
4.2 Unset packer & circulate 1 ½” hole volumes 4
4.3 Lay down Flowhead and surface lines 2
4.4 POOH with test string. 18
4.5 Lay down DST tools. 3
Total Kill Well and Retrieve Test String Time 29
Total Test Time – (hours) 170
Total Test Time – (days) 7

5.0. Appendix A Contingency Procedures

Table Tubing Leak – Contingencies
Tubing Leak Observed Condition Procedure
Inside Riser Drop in tubing pressure Close SSTT
Gas release on drill floor Close Tester Valve
  Bleed landing string pressure
Below SSTT Drop in tubing pressure Maintain kill fluid supply to annulus
Initial increase in annulus pressure
Circulating valve opens
Kill weight fluid in annulus flows into test string
Losses at trip tank - well self kills
Lower Test String Drop in tubing pressure Maintain kill fluid supply to annulus
Kill weight fluid in annulus flows into test string
Losses at trip tank - well self kills

5.2. TCP Misfire

  1. Wait 2 x times the calculated delay time
  2. Confirm valve configuration
  3. Confirm TCP firing head calculation
  4. Apply maximum firing head pressure and hold as directed by TCP specialist

  • Record volumes pumped to achieve maximum pressure and compare with previous figures

  1. Wait 2 x times calculated delay time
  2. Confer with head office
  3. Prepare to rig up slickline pressure control equipment to run drift to firing head to ensure communication path
  4. If communication path is established, RIH to retrieve firing head on slickline
  5. Re-dress and re-run firing head if problem identified
  6. If above procedure fails again, prepare to retrieve test string

5.3. Emergency Disconnect – Recommended

  1. Bleed annulus pressure to close tester valve
  2. Bleed tubing pressure to 0 psi
  3. Lubricate 9.0 ppg KCL brine above the tester valve
  4. Apply annulus pressure to open tester valve and bullhead fluid into formation
  5. Flow check for 15 minutes
  6. Bleed annulus pressure to close tester valve
  7. Adjust string weight to ensure SSTT is not in tension
  8. Close SSTT
  9. Activate hydraulic unlatch feature
  10. Pick up on landing string to above the blind rams
  11. Close blind rams
  12. Recover landing string

5.4. Emergency Disconnect – Insufficient time to Bullhead

  1. Bleed annulus pressure to close tester valve
  2. Bleed tubing pressure to 0 psi
  3. Lubricate 9.0 ppg KCL brine above the tester valve
  4. Adjust string weight to ensure SSTT is not in tension
  5. Close SSTT
  6. Activate hydraulic unlatch feature
  7. Pick up on landing string to above the blind rams
  8. Close blind rams
  9. Recover landing string

5.5. Emergency Disconnect – Immediate Disconnect

  1. Adjust string weight to ensure SSTT is not in tension
  2. Close SSTT
  3. Activate hydraulic unlatch feature
  4. Pick up on landing string to above the blind rams
  5. Close blind rams
  6. Recover landing string

Table Appendix B Casing and Tubing Data
  OD (in) ID (in) Drift (in) Make Up Torque (ft-lbs)
4 ½” PH6 L80 15.5 ppf 4.500 3.826 3.701 6000 ft-lbs Minimum 7500 ft-lbs Maximum
7” Vam Top L80 29 ppf 7.000 6.184 6.059  
9 5/8” Vam Top L80 47 ppf 9.625 8.681 8.525  

7.0. Appendix C Layout Drawing

Refer to figure 6.4

8.0. Appendix D P & ID

Refer to figure 5.21

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