To inform inspectors of the standards expected for the design and construction of offshore and onshore oil and gas wells.
There is no published national or international standard for the design and construction of oil and gas wells. Standards exist only for the manufacture of the components of wells such as casing, tubing and wellheads. Well operators, as duty holders for the design and construction of wells, tend instead to rely on their own corporate standards.
Since there is inevitably some variation between different duty holders’ corporate standards, the purpose of this document is to provide guidance to inspectors on what should be considered acceptable.
The relevant regulations are the Offshore Installation and Wells (Design and Construction etc) Regulations 1996, Part IV (Wells) regulation 13 (General duty), regulation 14 (Assessment of conditions below ground), regulation 15 (Design with a view to suspension and abandonment), regulation 16 (Materials) and regulation 18 (Arrangements for examination). The over-riding principle is that wells should be designed, constructed and maintained such that the risk of unplanned escape of fluids from a well is reduced to as low as is reasonably practicable. This requirement applies throughout the life of the well until it is finally plugged and abandoned.
4.1.1 A well conductor should be set to case off shallow, often unconsolidated, formations, to allow returns of drilling fluid to seabed or surface and prevent washout of seabed and to provide a foundation for blowout prevention and wellhead equipment.
4.1.2 Conductors should provide a competent foundation for the new well. Soils around the wellhead should provide adequate foundation strength to withstand offset loading on the wellhead. The conductor design should be adequate for the worst conditions of burst, collapse and tensile loading anticipated during drilling operations and subsequent life cycle of the well. The wall thickness and yield strength of the conductor and its connectors should be adequate to withstand the bending loads which may be applied to them throughout the life of the well. The conductor should have adequate foundation strength.
4.1.3 Conductors, and in the case of subsea wells, conductors and wellheads, should have adequate structural strength and fatigue life, to withstand cyclical weather and current induced loading as well as loads from possible snagging.
4.1.4 The setting depth of the conductor should be such that it isolates any shallow gravel beds or unconsolidated rocks, and that it should allow fluid returns back to seabed or the flow-line, while the next section of hole is being drilled.
4.1.5 If there is a possibility of encountering shallow gas in the next section of hole, the conductor shoe depth should be selected to minimise the risk of broaching occurring, caused by fracture of the sedimentary formations above the conductor shoe.
4.1.6 The height of cement behind the conductor can be critical in conditions where there are high lateral loads on the conductor and wellhead. The top of cement should be either at seabed or sufficiently below the mud-line to protect against bending induced failure.
4.1.7 The choice of conductor connection should be suitable for the method of conductor installation to be followed. Conductors may be driven as well as drilled and cemented in place. Connectors of a “quick connect” type should have a means of readily confirming that they have been fully made up and will not unlatch inadvertently.
4.2.1 Wells must incorporate sufficient casings, so designed and constructed to prevent blowout of well fluids at surface, subsea or underground, and to prevent the unplanned release of well fluids.
4.2.2 Casing should be manufactured, inspected and tested to the appropriate ISO specification, ISO 11960 (API Spec 5CT) Specification for Casing and Tubing. For sour service, materials used should conform to the requirements of standard ISO 15156 (NACE MR 0175) Materials for Use in H2S-containing Environments in Oil and Gas Production. Sour environment, where hydrogen sulphide is present, is defined in the standard.
4.2.3 The casing programme should be configured to accommodate all identified sub-surface hazards and to minimise risk either from cross-flow between formations or the uncontrolled release of well bore fluids to surface, throughout the life of the well. Casing setting depths should be selected to provide an adequate safety margin between the formation fracture pressure and anticipated pressures during well control or casing cementing operations. Limitations on well control pressures should be detailed in the design of the well.
4.2.4 Casings should be designed to withstand the worst conditions of burst, normal collapse, tensile and triaxial loading anticipated during drilling operations. All casing installed in the well should have adequate properties to contain the maximum loads to which it may be exposed during the lifetime of the well. There should be adequate allowance for deterioration in service from whatever cause, including wear, corrosion and erosion. Casings should be able to withstand the pressure of a full gas column or gas from the weakest exposed formation, whichever is less, with an adequate safety factor. Production casing should be able to accommodate a leak in the production tubing at the wellhead and withstand closed-in wellhead pressure plus a head of packer fluid. Where there is a possibility of casing failing in tension or collapse under worst case conditions, then the likelihood should be minimised by the use of suitable procedures.
4.2.5 The material specification of the casing should be suitable for the anticipated well bore fluids to which it may be exposed, especially those containing a significant concentration of hydrogen sulphide or carbon dioxide.
4.2.6 The design of threaded connections used should be appropriate for the service of the casing. Production casing for gas lifted wells should have gas tight (premium) connections.
4.2.7 All surface, intermediate and production casings should be pressure tested to an appropriate value for the well being constructed. This should be carried out prior to drilling out the shoe track or perforating. For production casing, the minimum pressure should be equivalent to the shut in tubing pressure on top of the annulus completion fluid. Where appropriate, consideration should be given to testing above the fracture pressure at the shoe.
4.2.8 Test pressures should not exceed the wellhead and BOP rated working pressure and 80% of casing burst pressure. Due consideration should be given to the burst rating of the weakest casing in the string, the density of the mud columns inside and outside the casing, the minimum design factors assumed in the casing design and the effect of pressure testing or bull-heading on casing tensile loads.
4.2.9 The integrity of a liner tie-back casing should be tested to exceed the worst case of maximum well shut-in pressure against gas, with a surface leak in the tubing and with packer fluid in the annulus.
4.2.10 Liner laps should be suitably inflow and/or pressure tested.
4.2.11 Up-to-date casing records should be kept, showing the current status of the configuration and depth of casing strings, formation tops, particularly porous zones and all hydrocarbon-bearing zones and cement tops and cement specification behind the casings
4.3.1 All hydrocarbon bearing zones should be isolated from surface. For all cementing operations, whether primary, remedial or plugging, the cement should be placed and checks carried out to ensure that the cementing objectives are achieved.
4.3.2 The quantity of cement must be suitable for the proposed operation in question. All conductors and surface casing should normally be cemented back to mud-line. Intermediate and production casing should, where appropriate, be cemented back to previous casing shoe and preferably back to mud-line for shallow strings (see exception below). Production casing should, where appropriate, be cemented to an acceptable height inside the previous shoe. A prudent excess is required to account for possible losses during placement and variation in diameter of open hole.
4.3.3 Exceptions to the requirement for cementing back to the previous casing shoe are:
4.3.4 The density of cement must be suitable for the proposed operation in question. The formations should be capable of withstanding the hydrostatic head of the cement column. Primary well control must be maintained while the cement is curing. Cement slurry density and spacer fluid should be sufficient to prevent any influx of well fluids.
4.3.5 The class of cement must be suitable for the proposed use; the slurry should be compatible with formation to be cemented and with anticipated temperature conditions.
4.3.6 Cement evaluation logs for verification of cement bonding are considered good practice for production casing and intermediate casing strings covering hydrocarbon bearing zones.
4.4.1 All wellhead equipment should be manufactured, inspected and tested to the appropriate ISO or API specifications, ISO 10423 (API Spec 6A) Specification for Wellhead and Christmas Tree Equipment, API Spec 17D Subsea Wellhead and Christmas Tree Equipment.
4.4.2 Wellheads and all components must be manufactured from materials compatible with the chemical composition of potential produced reservoir fluids. For sour service, materials used should conform to the requirements of standard ISO 15156 (NACE MR 0175) Materials for Use in H2S-containing Environments in Oil and Gas Production. Sour environment, where hydrogen sulphide is present, is defined in the standard.
4.4.3 Wellheads must have a rated working pressure that exceeds the maximum closed-in wellhead pressure that may be anticipated during the life of the well, including both the drilling and production phases.
4.4.4 Wellheads and all components must have a temperature rating compatible with the maximum wellhead temperature anticipated during the life of the well, including both the drilling and production phases.
4.4.5 Some designs of surface wellhead require the blowout preventers to be removed to allow access to install the casing hanger and annulus seal assembly. If the casing annulus is exposed to hydrocarbon bearing formations, there is risk that the well may flow from the annulus. The use of this design of wellhead should be discouraged unless there is adequate justification for using such equipment; and the well operator has adequate procedures in place to ensure that the casing annulus is fully isolated before the stack is removed.
4.4.6 Surface wellheads must have side outlet access to all annuli to allow pressure to be monitored and bled-off or fluids pumped from the annulus. During drilling or well intervention the side outlet must be fitted with a double full opening valve.
4.4.7 Gauges must be capable of accurately reading the full range of annulus pressures.
4.4.8 Well operators should have policies in place outlining allowable sidearm valve and plug configurations.
4.4.9 In common with the rest of the wellhead system, sidearm valves spools and flanges should be suitable to withstand maximum anticipated pressures. Their integrity should be tested not just on installation, but at routine intervals.
4.4.10 Surface wellheads should be equipped with two side outlets for each annular space between casings. Wellhead components above the surface casing housing should have a valve removal capability.
4.4.11 Where annuli are exposed to open formations, both casing spool side outlets should have valves fitted and should not be blanked off. This is to allow circulation across the annulus. For annuli not exposed to open formation the minimum configuration should be that at least one side outlet has a valve installed.
4.4.12 Where sidearm valves are likely to be cycled on a regular basis, a second valve should be installed on the outlet, and the outer valve used preferentially.
4.4.13 The tubing head should have both outlets fitted with double valve configurations. The outlets, valves apertures and annular space between casing and tubing should be sized appropriately to allow well kill.
4.4.14 Valve and gauge assemblies for monitoring annulus pressure must be suitable for anticipated pressures.
4.4.15 Well operators should have policies in place on allowable configurations of annulus valve and gauge assemblies. They should be configured to enable isolation and pressure bleed-off for removal or change-out of instrumentation or gauges. Assemblies should be mounted directly on to side-arms to minimise the risk of damage to extension pipe-work. Configuration should be such that a sidearm valve can be closed to effect isolation should the instrumentation or gauge assembly be knocked off the wellhead.
4.4.16 Instrumentation and gauges should be calibrated on a regular basis.
4.4.17 Well operators should have policies and procedures in place covering the use of valve removal plugs. Where valve removal plugs are used on wellhead side outlets to effect the inner isolation of a double isolation, solid bull plugs should not be used to effect the outer isolation. In such a configuration, failure of the valve removal plug could lead to trapped pressure which could not be safely vented. Where valve removal plugs are used to effect isolations, procedures should be in place to routinely check the integrity of such plugs, and change them out if required.
4.4.18 Well operators should have procedures in place for the safe installation and removal of valve removal plugs by use of the correct lubricator tool.
4.4.19 Valve removal plugs should not be routinely installed in both side outlets of an individual casing spool since this leads to inability to monitor annulus pressure.
4.4.20 Casing void spaces should be tested not just at the time of wellhead installation but at regular subsequent intervals to ensure the continued integrity of pack-off seals and ring gaskets.
4.4.21 Well operators should have procedures in place to ensure that fittings are not removed without first safely checking for and venting off any trapped pressure behind them.
4.4.22 Fittings (e.g. plugs, bleed nipples, tie-down bolts, and valve removal plugs) should be correctly identified and labelled. Some fittings with different functions and modes of operation may look the same. Fittings should be subject to controlled maintenance and certification to ensure their continued fitness for purpose.
4.4.23 Wellhead accessories (e.g. lubricators, test pumps, and stingers) should be subject to maintenance / recertification control to ensure their continued fitness for purpose.
4.4.24 Well operators should have procedures in place to ensure that pressure testing of wellhead components is safely carried out and pressure properly bled off after pressure testing.
4.4.25 Up to date records showing the current status of the wellhead system should be kept. Among other things these should record sidearm valve configurations, positions of any valve removal plugs, type and position of fittings such as bleeder and test plugs and instrumentation or gauge assemblies.
4.4.26 Well operators should have procedures in place to ensure that the configuration and status of the wellhead system is adequately communicated on handover of the system between departments (e.g. between production and drilling departments for workover operations. Handover communication should cover which valves are open or closed and any known system faults.
4.4.27 Wellhead Manuals for use at rig site should be controlled manuals.
4.5.1 All wells used for production or injection must incorporate a dedicated completion string incorporating the necessary safety devices.
4.5.2 Well completions should incorporate at least two barriers to flow between reservoir and surface, normally the tubing hanger and packer or polished bore receptacle and seal assembly.
4.5.3 The completion should include the facility to plug the completion deep, immediately above the reservoir and at the wellhead. There should be additional provision for plugging the well beneath potential intersection points.
4.5.4 All completions should incorporate a subsurface safety valve at an appropriate depth below the mud line to minimise the inventory of well fluids that could be released in the event of wellhead failure. The valve should be appropriate to the functional requirements of the well and in accordance with ISO 10432 (API Spec 14A) Specification for Subsurface Safety Valve Equipment. Subsurface safety valves will normally be surface controlled; however in water injection wells it may be permissible to install injection valves provided risk assessment concludes that it is safe to do so.
4.5.5 Suitable arrangements should allow the well bore to be adequately swept of well fluids by circulation.
4.5.6 For open-hole completions, formations between reservoir and previous casing shoe must be impermeable and competent.
4.5.7 The previous casing shoe must have a competent seal with cement verified and tested to a known leak-off pressure. The shoe should be set close to the pay zone.
4.5.8 The completion must incorporate a packer set inside the casing and as close to the shoe as possible.
4.5.9 Tubing should be manufactured, inspected and tested to the appropriate to ISO specification, ISO 11960 (API Spec 5CT) Specification for Casing and Tubing.
4.5.10 Production tubing incorporated in a well must be of a specification, including connection type, which is fit for the purpose of the well.
4.5.11 Tubing should be designed for worst case burst, collapse, tensile and triaxial loading.
4.5.12 Configuration of a wire-line set straddle packer assembly used to isolate a tubing leak assembly must not compromise the safe operation of the well.
4.5.13 Use of a straddle packer should not prevent installing a deep-set plug to isolate the perforations; this can be achieved by installation of an insert plug nipple in the original nipple.
4.5.14 Tubing repairs should be tested with an internally applied pressure greater than maximum shut-in wellhead pressure.
4.5.15 In the event that it is impossible to set a deep plug in the well, the repair should be externally tested to a suitable pressure which takes into account the worst case differential pressure across the patch.
4.5.16 Packers should be manufactured, inspected and tested to the appropriate ISO specification ISO 14310 (API Spec 11D1) Specification for Packers and Bridge Plugs.
4.5.17 Completion packers should be set as close, vertically, to the pay zone as possible.
4.5.18 In a well with a liner set, unless the liner hanger assembly includes an external packer, it is preferable to have the production packer set above the liner lap to isolate any potential leak path from the reservoir behind the liner.
4.5.19 Completion packers should be tested from above, to a pressure exceeding the worst case annulus pressure. In the case of gas lift or gas injection, the annulus above the packer should be suitably pressure and/or inflow tested before gas lift or orifice valves are installed.
4.6.1 The need for artificial lift should be assessed, the most appropriate method selected, and designed, installed and operated according to the Guidelines for Safe Design, Installation and Operation of Artificially Lifted Oil Wells, published by Oil and Gas UK (formerly the United Kingdom Offshore Operators Association).
4.6.2 In considering use of artificial lift, all options should be assessed. The risk to health and safety from the selected means of artificial lift must be as low as reasonably practicable.
4.6.3 The means of artificial lift should be reassessed on a regular basis to confirm that risks relating to the selected option are as low as reasonable practicable and that any new developments in technology or understanding of hazards are considered.
4.6.4 Where gas lift is assessed as being the most appropriate method of artificial lift, systems must be designed, constructed and operated in such a manner that they comply with the requirements of the Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995. Specific regulations that apply are: 9(1)(b) on preventing the uncontrolled release of flammable or explosive substances; 4(1)(a) on protecting persons from fire and explosion; and 5 on performing assessments.
4.6.5 Gas lift systems should be designed in accordance with API Recommended Practice RP11V6 Design of Continuous Flow Gas Lift Installations Using Injection
Pressure Operated Valves
4.6.6 Gas lift systems should be operated and maintained in accordance with API Recommended Practice RP11V5 Operation, Maintenance, Surveillance and Troubleshooting of Gas-Lift Installations.
4.6.7 Gas lift equipment should conform to API Specification Spec 11V1 Specification for Gas Lift Equipment.
4.6.8 Surface gas lift equipment should conform to API Recommended Practice RP 14C Analysis, Design, Installation and Testing of Basic Surface Safety Systems on Offshore Production Platforms and include all the recommended safety devices.
4.6.9 There should be provision for monitoring the gas lift pressure in the well.
4.6.10 There should be adequate means for blowing-down the annulus or gas lift injection string. This is essential for testing the gas lift down-hole safety device.
4.6.11 Gas should only be introduced to the well down tubing, or a casing to tubing annulus, that has gas tight connections. Connection types where the primary sealing mechanism is thread interference, such as Buttress, are not considered suitable. In addition it is important that Premium type connections are properly made-up and tested in order to affect a gas tight seal.
4.6.12 In exceptional situations it may not be practicable to retrofit Premium type connectors to an existing well without major modifications to the wellhead or risking damage to the pressure integrity of the well. In such circumstances it may be appropriate to introduce lift gas down casing with non-premium connections, but only after rigorous risk assessment has been conducted, indicating that risk is reduced to as low as reasonably practicable. The risk assessment must consider a number of factors including: (a.) the presence of other platform gas lift wells on-stream; (b.) the annulus design being capable of containing gas lift pressure; (c.) stable annulus response; (d.) comprehensive arrangements for monitoring annulus conditions; and (e.) a lift gas bleed-down system of with adequate capacity and responsiveness.
4.6.13 The well completion should be designed to minimise the gas inventory below the well-head and that which would be released to the installation in the event of wellhead failure. A surface controlled down-hole safety device should ideally be incorporated on the gas lift side on all platform gas lift wells. This should be either an annulus safety valve or a conventional SSSV installed in the gas lift string of a dual string completion. In the latter case there should be a dual string packer, or equivalent device, located above the uppermost gas lift valve in the production string. Such devices may also be desirable in subsea wells; however, risk due to an increased need for work-over, the requirement may need to be evaluated.
4.6.14 In exceptional circumstances there may be mitigating circumstances for using completions with single gas lift valves for well kick-off without installing annulus safety valves. To ensure that the potential volume of vented hydrocarbon is as low as possible, conditions imposed on gas lift kick-off from unprotected wells should include: (a.) well production annuli are depressurised and filled with brine after each kick-off operation; (b.) Only one well kick-off operation at any one time in wells with no annulus safety valve.
4.7.1 Christmas trees should be manufactured in accordance with ISO 10423 (API Spec 6A) Specification for Wellhead and Christmas Tree Equipment or API Spec 17D Subsea Wellhead and Christmas Tree Equipment.
4.7.2 The pressure rating of the tree should exceed the maximum expected wellhead pressure, including future reservoir treatment or injection. It is recommended that all trees on an offshore installation or land well site should have the same pressure rating.
4.7.3 The tree should be constructed of a suitable material, compatible with the chemical composition of the reservoir fluids. For sour service, materials used should conform to the requirements of standard ISO 15156 (NACE MR 0175) Materials for Use in H2S-containing Environments in Oil and Gas Production. Sour environment, where hydrogen sulphide is present, is defined in the standard.
4.7.4 The generally accepted minimum valve configuration on the production bore of all development well Christmas trees is: 2 x master valves, with the upper master valve hydraulically actuated and fail-safe closed; 1 x swab valve; 1 x hydraulically actuated fail-safe flow wing valve; one injection / kill wing valve.
4.7.5 The lower master valve should be manually or ROV operated and should not fail to the closed position or constitute part of the emergency shut-down system.
4.7.6 The use of a single master valve may be considered suitable for subsea trees where it is desirable to reduce the height of the tree and reduce the risk of snagging and in water depths or access inappropriate for manually or ROV operated valves. Only tubing-retrievable sub-surface safety valves should be run in wells with single valve trees, to avoid the risk of a wire-line retrievable valve unseating from the landing nipple and being displaced up the well bore into the tree area by production flow;
4.7.7 The use of horizontal trees is considered acceptable. Since they have both advantages and disadvantages for safety, their proposed use must be full risk assessed.
4.7.8 Horizontal tree assemblies are beyond the scope of API Spec 17D, Specification for Subsea Wellhead and Christmas Tree Equipment. Individual components of horizontal trees, however, are covered as listed in section 102.1 of Spec 17D and should comply.
4.7.9 As the master valves on a horizontal tree extend laterally from the body, they are potentially vulnerable to damage from dropped objects and in the case of subsea trees from snagging by trawl boards. Adequate protection against these must be provided.
4.8.1 All development wells, whether used for production or injection, must have procedures in place for monitoring all annulus pressures and tubing / annulus communication. The procedures should take full account of the specific circumstances of the well and must specify allowable leakage rates and anomaly reporting criteria.
4.8.2 Where there is an anomaly, production or injection should not continue unless the situation has been fully risk assessed and the conclusion reached that it is safe to continue.
4.8.3 Sub-surface (or down-hole) safety valves (SSSV / DHSV) must be function and pressure tested at appropriate intervals as recommended in ISO 10417 (API RP 14B) Design, Installation, Repair and Operation of Subsurface Safety Valve Systems. ISO 10417 specifies a maximum testing interval of six months, unless local regulations, conditions or documented historical data indicate a different testing frequency. Testing procedures must include clearly defined acceptable leak rates.
Further information can be obtained from Head of Discipline – Well Engineering and Operations OSD 1.4.