The objective of this article is to describe minimum requirements for planning, drilling, and testing HP or HT wells and highlights the areas of concern that need extensive consideration when drilling HP or HT wells.
DEFINITION
There are different definitions of what comprises an HP/HT well: one of the most common used by major operators is linked to the expected shut in pressure and/or the expected reservoir temperature:
- The expected shut in pressure must be higher than 690bar (10,000psi).
- The expected well temperature must be higher than 150 OC (±300OF).
The NPD in Norway add to this definition a concept of depth where wells deeper than 4000m (>13,100ft) should be considered as HP/HT, which is not the case in the UK sector of the North Sea.
The UK DECC defines HP/HT as reservoir pressure exceeding 10,000psi (690bar) and temperature above 300 OF (150 OC). In the UK, HPHT is formally defined as a well having an undisturbed bottom hole temperature of greater than 300°F [149°C] and a pore pressure of at least 0.8 psi/ft (~15.3 lb./gal) or requiring a BOP with a rating in excess of 10,000 psi [68.95 MPa]
GENERAL
1. The Well Operations Manager shall ensure that specific procedures are produced for any HP/HT wells.
2. Should any well unexpectedly be re-classified as a HP/HT or where pressure could exceed the rating of the well equipment, then drilling/testing operations should be suspended and the well be made safe.
3. Should any HP/HT well encounter conditions whilst drilling/testing that are in excess of any conditions on which the original Basis for Design was carried out, drilling/testing shall be suspended until the potential impact is assessed. Drilling or testing shall only re-commence upon receipt of approval from the Affiliate Well Operations Manager.
PLANNING
1. A detailed study of pore pressures, reservoir properties, formation fracture gradient, temperature profile and all pertinent geological information shall be carried out prior to planning any HP/HT well.
2. This information must be conveyed to those directly involved in monitoring pore pressures on the rig (well operations supervisors/engineers, drilling contractor personnel and mud loggers).
3. The well design (casing, tubing or DST) shall be done using specialised software, Wellcat© or equivalent, which uses a qualified temperature modelling module.
4. The results of the design must be QA/QC’d by a Wellcat© specialist.
5. The well design (casing, tubing or DST) shall be peer reviewed.
6. A Well Programme shall be prepared and will contain the following minimum information:
a. Kick tolerance shall be defined, in terms of pressure, volume, and depth, to determine when drilling can no longer be safely continued without contingency measures,
b. Whereby the miscibility of the gas in mud under HP/HT condition must be taken into consideration for the calculation of kick tolerance.
c. In HP/HT condition Boyle’s law is not directly applicable for the calculation of well control. Specialised software must be used for the calculation of kick tolerance (e.g.Drillbench)
7. The well plan should address the objectives of each section, e.g. the purpose of each casing string and cement job (casing design manual).
8. Drilling fluid selection shall be made with due consideration to the HP/HT environment, whereby the drilling fluid programme shall consider mud stability, chemical selection, rheology of heavy fluids and swab/surge pressures under HP/HT conditions.
9. In case of very low drilling margin (<1 ppg) the ECD, swab/surge must be calculated using specialised software such as Drillbench.
10. Cement slurry and spacer design requirements must be established in the light of the HP/HT environment, with appropriate consideration being given to the temperature profile.
11. A review of placement techniques and wellbore pressures behaviour shall be included which take into consideration the hydrostatic pressure regression during the initial setting time, which could lead to annular gas flow.
12. Kick detection and well control philosophy, shall be developed in the Joint Drilling Manual prepared with the drilling contractor and shall address:
- The definition of the drilling margin (pore pressure v fracture gradient evaluation and kick detection) and operational practices to be implemented to ensure safe drilling of the HP/HT zone.
- Definitions of:
- Losses,
- Acceptable level of gas,
- Wellbore breathing,
- Flow check and acceptable flow check,
- Drilling breaks.
13. Fingerprinting must be detailed in the Joint Drilling Manual, whereby fingerprinting operation must take place prior to drilling the shoe of the production casing or liner and prior to entering the reservoir.
14. The Joint Drilling Manual shall define the conditions under which drilling should cease due to the inability to detect a well flow; for example when lost returns are experienced.
15. The Joint Drilling Manual shall include details of influx detection methods and shut in procedures to be used.
16. In exploration wells when drilling the reservoir section, if the well is shut in because of loss/gain situation, the well can be bled off by steps:
- 1st Bled volume must not exceed 5 bbl – This volume can be increased later when the nature of the influx is clearly identified, wherein it is established that said bleeding will not underbalance the well during circulation (impact on mud SG)
- Each bled volume must be circulated out of the well before proceeding to the next bleed operation
17. The Joint Drilling Manual shall include a discussion of kill methods with clear reference to the circumstances in which a given method will be used.
18. Details of lost circulation strategies must be included with the Joint Drilling Manual.
19. Discussion concerning bullheading and its application shall be documented.
20. Establishment of the responsibilities of personnel during well kill operations including communications paths and means by which competence will be assured shall be included in the Joint Drilling Manual.
21. The Joint Drilling Manual shall include guidance on kill circulation rates. If a kick is to be brought to surface, definitions of the conditions which will dictate a reduced kill circulation rate and the decision to bypass overboard.
22. Procedures to prevent and deal with hydrate formation and H2S shall be documented.
23. The programme shall include estimates of bubble-point of reservoir fluids, (if possible), to determine when and where in the well gas breakout may occur.
EQUIPMENT
1. Rigs used to drill HP/HT wells shall be fit-for-purpose with sufficient and suitable power and equipment.
2. The rig shall have sufficient variable load capacity to run heavy casing strings with all of the drill string set back without having to offload critical well equipment.
3. Well control equipment, mud pumps and stand-pipe manifolds must be subjected to a detailed technical inspection as part of the rig selection process to confirm that the equipment matches the pressure and temperature requirements of the well.
4. The following considerations shall apply when selecting well control equipment for drilling high- pressure wells:
- Maximum expected pumping pressure while drilling for all the well sections.
- Mud temperature prediction when drilling
- Elastomer selection – High temperature
- Temperature and pressure monitoring
- Gas hydrates formation
- Mud gas separator capacity and design (hot mud line) that must be able to cope with large volume og gas
- High pressure Float valve for the BHA
- BOP/ESD control system.
5. Measurement While Drilling (MWD); equipment and downhole motors shall be selected according to their temperature ratings. Ability to pump LCM shall be considered during selection.
6. Finger printing must be taken prior to drilling out the production casing shoe track or any casing immediately above an HPHT pressure transition.
HPHT WELL TESTING
1. Well testing objectives must be clearly established at the FEED phase of the project so that the well is designed and the DST planned according to these objectives.
2. Ensure the well architecture has been designed to handle the planned DST programme (load cases planned compare to actual when drilling the well).
3. Tubing design shall be made using specialised software, Wellcat© or equivalent. Load cases should be chosen to simulate all planned operations (e.g. tubing movements during flowing periods, downhole shut in, well killing with cold fluid at the end of the DST).
4. Data from logging (Bottom Hole Pressure, Formation Fluid Gradient and Bottom Hole temperature) shall be compared to the values used for the DST design. The design should be reviewed in light of this data.
5. All HP/HT well tests shall be conducted through a permanent packer or a field proven (in similar conditions) permanent retrievable packer. In any case weight set packers are forbidden.
6. Any DST string should include as a minimum a downhole shut in/circulating device, two downhole shearable circulating devices, one fail safe safety valve below the BOP.
7. The tubular connections in the DST string shall be premium metal to metal sealing connections.
8. The well testing programme shall include contingency plans to ensure well integrity for all foreseeable situations, including:
a. DST tools failure including firing head
b. Leaks in string above/below closed BOP rams, surface leaks, a decision tree shall be prepared and included in the programme.
c. Weather limitations (including zero wind) and level of alertness
d. Emergency ESD for the DST and installation
e. Emergency shear of string across BOPs
f. Kick control procedure when tripping the DST string.
g. Gas hydrate inhibition.
9. The use of surface read-out downhole gauges is not allowed.
10. The use of flexible high-pressure hoses is subject to their suitability for the test conditions and their certification. A rigorous quality assurance and testing programme of these lines is essential.
11. All flowline connections between the flowhead and choke manifold shall be metal to metal sealing.
12. All DST equipment shall be H2S resistant.
13. The surface well test equipment shall be designed/sized for the expected flowrates. The design should be peer reviewed.
14. Equipment limitations in terms of flow rate and flowing temperature shall be determined and not exceeded for any reason.
15. Rig heat protection must be designed to handle the DST maximum planned flow rate. Heat radiation simulations shall be performed.
16. The DST maximum planned flow rate shall not be exceeded during the DST operation.
17. When well testing with an underbalanced annulus fluid the well test packer shall be tested from below to the maximum forseable differential pressure + a suitable safety margin.
MISCELLANEOUS
1. 24-hour supervision by Company personnel when working in HP/HT zones shall be maintained.
2. Zone abandonment planning is of critical importance, especially where additional lower pressure zones are to be tested above the zone to be abandoned.
3. Wellsite emergency response plans must be established for the specific well.
4. A relief well contingency plan is to be produced that covers the following points as a minimum:
a. Identification of contingency drilling locations.
b. Required wellbore surveying programme for original well and relief well to ensure adequate interception capability.
c. Conceptual well kill scenarios, one relief well should be suffisiant to kill the uncontrolled well
d. Conceptual tubular design for well kill.
e. Well kill organisation and responsibility
f. Sources of contingency well control equipment, drilling rig(s), support vessels (if offshore), tubular, and wellheads.
5. Full consideration must be given to the required well control training for the operation, and that all appropriate personnel have received adequate training in the relevant areas.
6. The drilling contractor's training programme is to be audited with respect to key areas (HP/HT reservoir drilling, tripping procedures in HP/HT environment, well control, H2S).
7. In addition to routine well control drills, it is required that drills involving non-routine situations and emergency shutdown procedures are conducted with the different crews.