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Testing Standards

1 INTRODUCTION

This document provides the minimum requirements and practices for planning and carrying out well testoperations.

2 REFERENCES

API RP 14C
API RP 521
API RP 520
NACE MR-01-75

Other Standards:
- Barriers
- Pressure Testing
- Coiled Tubing
- H2S

3 GENERALITIES

3.1 TEST DESIGN AND PREPARATION

1. Any test shall be properly designed so as to comply with the COMPANY Casing and Tubing Design Manual, WOR, Industry Standards and Best Practice.

2. The following minimum topics shall be considered during design:

  • Has the well casings been designed to handle a DST?
  • Maximum pressures at surface, during production, bull heading or shut in.
  • Maximum collapse forces during flowing operations including operation of annulus pressure
    controlled valves.
  • Tension and compressive forces resulting of the tubing movement on the DST string must have been calculated using specialised software. This software shall have a thermal model if the reservoir temperature is more than 100°C (215°F).
  • Potential pump out force on the tubing string, including pressure tests.
  • Potential for sand production
  • All different risks associated to a DST operation
  • Any H2S service requirement for the equipment, training for personnel
  • H2S breathing apparatus for the personnel
  • Any additional measures required for HT/HP testing such as using a permanent production packer
  • CO2 and any chemicals that may be used
  • Hydrate formation.

3.2 OPEN HOLE DST

1. Open hole tests are forbidden on floating rig and HP/HT wells. Note: In very specific conditions a dispensation can be requested to the Group Well Operations Manager.

2. Open hole test shall not be carried out without approval from the Affiliate Operations Manager and shall involve carrying out a detailed study and risk assessment taking in to account:

  • The volume to be flowed into the wellbore,
  • The reservoir pressures,
  • The presence and location of other potentially productive zones or permeable zones,
  • The reservoir temperature,
  • The hole deviation,
  • The open hole length, condition and geometry,
  • The nature of the reservoir fluid,
  • The potential and concentration of H2S.

3.3 TESTING PROGRAMME

1. Every well test shall have a detailed testing programme that shall include as a minimum the following:

  • Organisation and responsibilities on site,
  • Test objectives,
  • Equipment requirements with layout and installation plan,
  • Sampling programme,
  • Shut in and flowing time,
  • Expected conditions and fluid properties,
  • Well kill procedure, detailing mud weight and overbalance,
  • Suspension and abandonment plan,
  • Test pressures for equipment,
  • Equipment failure contingency plan,
  • H2S contingency plan,
  • Safety programme and safety drills,
  • Logistic and helicopter management during well test especially if flaring is planned,
  • Incident reporting.

2. All test programme amendments shall be approved by the Well Operations Manager and the participants in the original approval.

3.4 ROLES AND RESPONSIBILITIES

  1. The Well Operations Supervisor shall be in overall charge of any well testing operation at the rig site.
  2. The Well Operations Superintendent shall have the onshore responsibility.
  3. A pre-test meeting shall be held with all relevant personnel present prior to commencement of operations. Roles and responsibilities are reminded during this meeting.
  4. All BOP’s and surface pressure control equipment shall be pressure tested prior to running in hole with the test string to the maximum possible surface pressure.
  5. Unless approved by Well Operations Manager the BOP rams shall fit the different DST string diameter. The well shall be closed on fixed rams.
  6. Fill up lines and pumps shall be function tested prior to running the test string.
  7. All temporary test lines shall be secured at each end and along their length prior to testing.
  8. A full function test of all emergency systems, automatic valves and other test systems shall be carried out before testing.
  9. A full test of the heat protection of the platform (Water wall) shall be done prior to start flowing the well.
  10. Gas detection equipment shall be located at key points and checked prior to testing.
  11. A minimum of one complete hole circulation shall always be carried out prior to pulling out of hole with a test string.
  12. Sufficient lighting shall be installed for night operations.

3.5 EQUIPMENT PREPARATION

3.5.1 HSEQ MANAGEMENT

1. All equipment shipped and temporarily installed on the rig shall have an HSEQ plan and assigned supervision and responsibility for its implementation.
2. Safety critical operations such as pressure testing shall conform to the rig’s barrier policy and shall be strictly adhered to. They shall be covered by Rig Contractor permit to work.
3. The Well Operations Manager shall ensure the allocation of responsibilities between different service groups (service contractors, drilling contractor and the COMPANY representatives).
4. The responsible person shall inspect the work area prior to the safety critical operations to
ensure compliance to regulations.

3.5.2 COILED TUBING

1. Should CT or wire line unit be used, additional safety device should be installed.
2. If some sand is foreseen whilst testing on floating units, intervention with CT shall be planned in case of plug off of the DST sting.
3. If coiled tubing is to be used on a semi-sub rig, a CT frame has to be installed.

3.5.3 SURFACE EQUIPMENT

  1. All equipment from the flow-head to the choke manifold shall have a working pressure greater than the maximum possible SIWHP, with a safety margin of at least 10 %.
  2. All equipment from the choke to the separator shall either have a safe working pressure greater than the maximum SWHP plus a safety margin of at least 10% or be independently protected
  3. All separators must be protected by two independent relief systems (PSV's or rupture discs). Rupture discs must have a completely independent vent line. The PSV's may be piped back into the gas outlet line.
  4. When positioning the vent lines, the position of the air inlet of the living quarter must be taken into consideration.
  5. A manual ESD system should be incorporated in well testing hook-ups both on and offshore. ESD valve response (closure) time should be less than 15 secs, with zero pressure in line.
  6. When hydrocarbons are flared (e.g. offshore) it is necessary to supply air to the burners to aid combustion. This air must be provided from an independent air supply, not linked to any other rig air system.
  7. At least 3 check valves must be incorporated in the air supply line, one at each burner and one isolating the compressor.
  8. The use of drill pipe for the testing operation shall be prohibited. Dispensation may be obtained under certain specific circumstances.
  9. For all testing H2S service tools and subsea equipment complying with NACE MR-01-75 latest edition must be used. Dispensation may sometimes be obtained in the case of
    appraisal wells where the reservoir fluid properties are known
  10. At least two (2) different reverse circulating devices (normally reversing valves) working on different principles must be included in the DST string.
  11. On floating rigs, an annulus pressure operated downhole tester and/or safety valve must be incorporated in the DST string, below the BOP level.
  12. On Jackup and land rigs, a failsafe valve (hydraulically operated) must be installed below the BOP level (normally below mudline). A tester and/or safety valve, either mechanically
    or annulus pressure operated, is also required, except in cases where a Xmas tree and tubing hanger are installed.
  13. Permanent packers (or field proven permanent retrievable packers) are mandatory for gas tests or if the expected pressure is in excess of 5000psi for oil tests. In any case, weight set
    packer are forbidden.
  14. 14. Tubing puncher shall be available on site when carrying out testing operations. Whenever pressurized Nitrogen is used for loading DST tools, ensure Oxygen levels in the nitrogen are less than 1 %. This shall be carried out by the supplier prior to dispatch of Nitrogen to the rig. Silicone grease should be used to mitigate the risk of explosion.
  15. On floating rigs, a subsea test tree/valve system, with failsafe hydraulic controls and hang off system must be installed for testing operations.
  16. When subsea BOP is used especially in deepwater conditions extreme care shall be taken not to apply external differential pressure across the BOP, the well head or X- tree. This condition is likely to occur when reversing out formation gas or nitrogen.
  17. Temporary piping shall be subject to the following:
    a. For H2S Service, connections must be welded or integral
    b. For Standard service quick-union type connections, Manufacturers' Cold Working
    Pressure (CWP) ratings must exceed the maximum anticipated sour gas service
    conditions by either 345 bars (5000 psi) or 100 %, whichever is lower.
  18. Metal to metal seal (clamp hub or flanged type or quick union) connections are recommended where:
    a. Shut-in or flowing pressure may exceed 42 MPa (6 000 psi),
    b. Flowing temperatures may exceed 100°C (210°F),
    c. Flowing temperatures may be below -30°C (-20°F),
    d. H2S levels in excess of 5 psia partial pressure are anticipated,
    e. CO 2 levels in excess of 1000 psia partial pressure are anticipated (10 % at 10 000 psi).
  19. The use of chiksans with swivel is prohibited.
  20. All temporary pipe sections must be secured to fixed rig structures.
  21. Use of chiksans between the flowhead and the choke manifold is not permitted. Coflex hoses shall be used instead.

3.6 VOLUME BELOW PACKER

1. The maximum volume of fluid that can be left below a test packer prior to unseating is as below:
a. Exploration wells with reservoir pressure below 690 Bar (10,000psi) 1.5 m3.
b. Exploration wells with reservoir pressure above 690 Bar (10,000psi) 1.0 m3.
c. For either case the maximum dry gas volume at surface conditions shall be less than 750 m3.
d. For appraisal well with known reservoir fluid properties derogation may be sought for a larger volume.
e. Setting depth of the packer shall be taken into account to define the density of the killing mud.

3.7 NIGHT OPERATIONS

  1. Under-balanced perforation operation is prohibited at night.
  2. First flow shall always take place during day light.

3.8 PERFORATING STRING UNDERBALANCED TCP PERFORATING

  1. The string should comprise at least a packer, an annulus pressure controlled circulating/shut off valve (e.g. Omni Valve) and at least one single shot circulating device
  2. If the operation is to underbalance perforate then well kill following immediately, a weight set packer is acceptable
  3. A shooting string with premium connections (e.g. PH-6) is mandatory in gas or high GOR wells, dispensation may be sought for oil wells
  4. Regulation 3.5.1 applies and the parts of 3.5.3 which are applicable
  5. Regulation 3.6 applies
  6. Regulation 3.7 applies