This document provides completion design standards and requirements and specifies general practises that facilitate efficient and reliable completion design.
GENERAL
The completion shall be designed to produce safely and economically effluent to surface. In completion design, simplicity is synonymous with reliability.
WELL INTEGRITY
Well integrity is the application of people, equipment and processes throughout the well’s life cycle.
The completion / well shall be designed & installed so as to ensure that there can be no unplanned external escape of hydrocarbons and the risk of injury to personnel is as low as reasonably practicable (ALARP).
The well should be in a safe condition at all times. The focus overall should be on the safe physical condition of the well rather than the actual operations being carried out.
Temporary BOPs (wireline, coiled tubing etc.) are to be considered as part of the well’s operating envelope when deployed. Suitability, maintenance and testing procedures should be similar to those required for drilling BOPs i.e. considered to be SCE (Safety Critical Elements).
This document states the barrier requirements on completed wells for that purpose.
Barriers should be explicitly described in procedures and plans. The description can be a schematic, a matrix or descriptive text. Operations reports (DDR or similar) should explicitly describe the installation & testing of any barrier.
DEFINITIONS
1. Barrier: A component is validated as a barrier if it is qualified for expected fluid characteristics and if the following criteria are validated
- a. an “active” component can only be considered as a barrier if it has been successfully pressure tested in its closed position in the direction of the flow if possible.
- b. a “passive” component can only be considered as a barrier if it has been successfully pressure tested at its installation and if its integrity has not been compromised by operations.
2. Non-eruptive or non–flowing well:
- a. once the injection/activation system is stopped, once the injection/producing bore had been bleed-off to atmospheric pressure and once well mean temperature is stabilized, no flow (liquid or gas) can be observed at surface. This test shall be repeated at least once a year or more often if reservoir conditions change.
3. Annulus A: casing/tubing annulus (tubing x production casing is designated the ‘A’ annulus. The following annulus moving outwards is then designated ‘B’ annulus, ‘C’, ‘D’ etc.)
4. Internal envelope / Primary barrier – made up of:
- a. the production/injection packer
- b. the tubing
- c. the downhole SCSSV or any other downhole barrier.
5. External envelope / Secondary barrier – made up of:
- a. the production casing cement and annulus fluid
- b. the casing
c. the well head and the Xmas Tree (the global X-mas tree arrangement shall be considered with the well-head as a unique barrier).
RELATED EQUIPMENT
1. SCSSV:
- a. if a WL retrievable SCSSV is chosen, the bad anchoring issue is a risk to assess and mitigate (positive locking system could be a remedial)
- b. The valve shall be regularly function tested and leak tested in the closed position. An adequate frequency has to be established. The replacement frequency of a WL SCSSV shall also be defined, for scale and corrosion purpose.
2. Wellhead: the annulus valves shall be regularly function tested and leak tested in their closed position
3. Xmas tree: To be regularly function tested and leak tested.
4. Surface control by-pass valve (on artificial lifted wells with ESP): to be regularly function tested and leak tested.
DIAMETERS
1. The completion design shall take into account potential future intervention requirements. Generally, a monobore completion will allow for better access and facilitate a wider range of intervention activities.
2. The ID of different nipple profiles shall ensure that the service tools of the deepest profile will pass through all of the upper profiles. The possible interferences between the different profiles shall also be identified (e.g. protection sleeve of the SCSSV).
3. The tubing/casing annular clearance shall facilitate the installation of control lines (TRSCSSV, chemical lines, gauges, etc).
RELIABILITY
1. Potential leak paths have to be identified and addressed:
- a. Dynamic seals of expansion joints, contraction joints..
- b. SSD above the production packer. Alternative solutions such as SPM + gaslift orifice shall be evaluated.
- c. Electrical connections below the tubing hanger
- d. Chemical injection mandrels and connectors
2. SCSSV:
- a. Sealing components of the actuator system. The requirement for a back up metal to metal seal in the fully open or fully closed position has to be evaluated.
- b. The requirement for a self equalizing device shall also be assessed
- c. A choice between WL retrievable and Tubing retrievable shall now be made bearing in mind that TRSCSSV are now very reliable and have the advantage of dramatically reduced maintenance costs when compared to WL retrievable alternatives.
- d. The SCSSV setting depth shall be determined by taking into consideration the hydrate formation zone and shall be in compliance with spec API 6AV1 – Specification for Verification Tests of wellhead Surface Safety Valves and Underwater Safety Valves.
INTERVENTION CONSIDERATIONS
1. SCSSV: the availability of an isolation sleeve for well intervention has to be assessed.
2. Packer retrieving system (if any), associated releasing/milling procedures and tools required (milling extension etc.) shall be defined at the design stage.
3. Sliding Side Door (SSD): the need has to be well evaluated knowing that large diameter SSD can be difficult to operate when set deep.
4. An alternative to SSD can be a Side Pocket Mandrel (SPM) with a circulating valve.
5. Operations related to tubing test, packer setting and packer fluid displacement shall be assessed and compared to trip saver components (Schlumberger TIVF etc.)
6. Well servicing such as slick-line, wire-line, CT, tractor shall be defined at the completion design stage.
7. A review shall be made with the wire-line specialist/wire-line company to check the compatibility (ID, OD, drift) of all planned slick-line interventions tools with completion components and tubing.
8. Choice of nipple type (no-go, full bore) shall be defined with regards to the foreseen pressure range.
9. Design shall take into account the potential future need of artificial lift in depleted conditions (Side pocket mandrel etc.).
10. Interventions in subsea environment are expensive therefore the completion shall be design to mitigate the future risk of work-over. The following points shall then be studied:
- a. permanent pressure and temperature monitoring system
- b. packer setting valves
- c. intelligent valves (for selective completions)
- d. reservoir isolation valves
- e. deep set SCSSV (spring type or nitrogen chamber type).
11. Isolation of the reservoir whilst running the upper completion shall take into account new equipment
e.g. formation isolation valves, which isolate the reservoir without the need for an additional trip to activate.
CONTINGENCIES
All the potential failures of equipment during installation, production and removal shall be identified. A contingency plan shall then be issued to propose back-up solutions or mitigations to each identified risk.
MECHANICAL PROPERTIES
1. Mechanical properties of completion components shall meet or exceed the tubing mechanical properties.
2. When an anchor latch device is used, the mechanical resistance of its connection shall be able to take the load charge of the tubing design.
3. Packer type and characteristics shall be determined according to the different load forces and temperature variation it is going to see during its life.
MATERIALS
1. Tubing material, grade and connection: refer to Casing and Tubing Design Manual.
2. Fluid type and well conditions will drive the choice of material.
3. Risk of galvanic corrosion will be evaluated if components and tubing made from a different material.
4. Risk of galling shall be assessed when running stainless steel pipes from 13% Cr and upwards.
5. In the medium to high temperature range (above 100°C), a specific study must be carried out to define the materials to use for sealing (SCSSV, O rings, static seals, locator seal assemblies, expansion joint, SSD, packer element).
6. Hydraulic and injected fluids shall be selected according to expected temperatures. Specific compatibility tests shall be performed onshore to avoid a mixture of non compatible fluids.
7. Erosion issues shall be identified to determine a specific metallurgy (for both injector and producer wells) to be used.
8. The elastomer selection process should be designed to take account of the major causes of elastomer seal failure i.e. chemical degradation and extrusion / explosive decompression.
9. Define all the service conditions.
10. ALL eventualities and possibilities should be taken into account to ensure optimal materials selection, including the range of possible temperatures and pressures and the complete fluid environment, with the likely production chemicals.
11. The tropical or marine atmosphere shall be considered for corrosion issues.
STRESS ANALYSIS
Under normal cicumstances the tubing size and metallurgy (metallurgy may have an impact on the stress analysis) will have been determined prior to any stress analysis being performed.
In order to check the grade/weight of tubing required a triaxial stress analysys should be performed using the proposed (or actual, if available) well trajectory.
If software is not available then a competent third party should be used to perform the work.
Minimum requirement is tabled below. Other installation / production loads to be examined on a case by case basis. Any possible change of duty should be included.
T & D analysis should also be performed as required (running sand screens in open hole for example).
*Vendor connection compression allowance may be less than the tension allowance. If coupling is derated in compression via the software the axial compression safety factor is 1.0.
Packer working envelope to be supplied by vendor. All load cases to be plotted on packer working envelope.
Friction disabled if option allowed. Temperature deration enabled if option allowed.
EROSION
This is a particularly complex subject and will require specialist advice if the expected operating conditions are severe. A first pass velocity limit for avoiding erosion should be taken from API 14E (Design and Installation of Offshore Production Platform Piping Systems).
The following formula will apply:
o Vcritical = C / (m)
Where:
o Vcritical = Fluid threshold erosional velocity. (Ft/sec)
o C = Empirical constant. (See table below)
o m = Gas/liquid mixture density. (Lbs/Ft3)
The following table gives the C values to be used for various metallurgies in nominally solids free service
(i.e. solids < 1Lb/1000Bbl).
RUNNING THE COMPLETION
Running procedures should optimise rig time but always prioritise the safety of personnel and of the installation.
PREPARATION AND TRANSPORTATION
1. Base preparation: QA/QC plan to define the checks to be performed on the equipments delivered to the base, the storage procedures and the preparation before sending equipments to the rig.
2. Offshore preparation: checks to be performed on the equipments received onboard and preparation procedures (drift, removal of storage grease on tubular threads, tubing tally…)
OPERATIONS PROGRAMME
1. Completions shall be performed according to a detailed Well Operations Programme.
2. This Programme shall detail the organisation, responsibilities and reporting links on the well site. The Well Operations Programme shall include:
- a. Detailed procedures showing the different barriers in place during the different phases of the completion operation.
- b. Cleaning procedures (and related BHA: scrapper, magnet, patroller) to be followed prior to run the completion.
- c. Completion fluids:
- o Fluids characteristics and preparation procedures
- o Fluids displacement procedures taking into account the equipments limitations (packer element, liner top, etc).
- d. Correlation depths references must be clearly detailed in the completion programme.
- e. A detailed completion schematic diagram, mentioning: OD, ID, depth, connections type, linear weight, metallurgy, grade, make-up torques of the different components.
- f. Sub-assembly details.
- g. Appendix: User’s manual for each equipment, including: functionality, technical data (dimensions, metallurgy, and mechanical procedures), handling procedures, running procedures, contingency procedures and an engineering drawing.
- h. Handling:
- o The handling procedures, especially for long assemblies and equipments sensitive to bending loads.
- o For chromium pipes and components: a specific storage, transportation, and running procedure, as well as proper running and handling equipments. It may be helpful to have a manufacturer service engineer on-board to supervise the tubing running in that case.
SAFETY BRIEFING
1. Safety briefing shall cover the identified potential hazard linked to a non routine operation like running a completion
2. The required running equipments and their characteristics (including back-up).
3. Test procedures and values. Direction of the test and value shall be justified.
4. Well clean up procedure.
5. When applicable inflow pressure test of the liner top.
6. Pressure test values and justification for equipment.
7. Interventions: if any (slick line, CT, the related procedures.
8. Equipment failure contingency plans and associated procedures.
ZONING
Area classification is a method of analysing and classifying the environment where explosive gas atmospheres may occur. The main purpose is to facilitate the proper selection and installation of apparatus to be used safely in that environment, taking into account the properties of the flammable materials that will be present including taking into account non-electrical sources of ignition, and mobile equipment that creates ignition risk.
Hazardous areas are usually classified into zones (European definition used) based on an assessment of the frequency of the occurrence and duration of an explosive gas atmosphere, as follows: (local rules may apply/supercede).
- a. Zone 0: Area in which an explosive gas-air mixture is continuously present or present for long periods.
- b. Zone 1: Area in which an explosive gas-air mixture is likely to occur for short periods in normal operation.
- c. Zone 2: Area in which an explosive gas-air mixture is not likely to occur, and if it occurs it will only exist for a very short time due to an abnormal condition.
It is important the any zoning requirements are taken into account when units with prime movers are present at the rig site. Wireline/logging winches, CT power units, pumps etc. As a minimum only zone 2 rated prime movers (including electric motors and internal combustion engines) should be used at the rig location. Any other equipment used should be subject to a formal in-depth risk assessment.
API RP500 is generally used as guidance for zoning of offshore well test equipment. The rig owners should always be consulted on zoning requirements. If in doubt about equipment suitablity, competent, professional advice should be sought.
RUNNING THE COMPLETION
1. The completions plan shall be approved by Well Operations Manager. Any deviation or amendment shall be approved both by Well Operations Manager and the original approvers.
2. The Well Operations Supervisor shall be in overall charge of all completion operations at all times. Depending on the nature of the work (drilling, or workover) the Well Operations Supervisor may be either a Well Operations Supervisor or a completion specialist. The Well Operations Manager shall appoint the Well Operations Supervisor.
3. The Well Operations Supervisor shall ensure that all components of completion equipment shall have all dimensions checked and shall be drifted at the well site.
4. All pressure-containing completion equipment, with the exception of tubular, shall be pressure tested to the maximum operating pressure plus safety margin before running into the hole. Pressure tests not performed at the well site (i.e. pre-tested sub-assemblies) shall be certified and Pressure Test Certificates available.
5. All surface completion equipment upstream of the choke shall be pressure tested to the maximum operating pressure plus a safety margin before flowing the well. Equipment downstream of the choke shall be tested to rated working pressure. A full function test of valves and automatic systems shall be carried out.
6. All gas detection and safety equipment should be checked prior to starting completion activities.
7. A detailed Completion Diagram including valve status, barrier details and details of completion fluids in place shall be prepared by the Well Operations Supervisor