NORSOK standard D-010 Rev. 3, August 2004

Transcription

1 7 COMPLETION ACTIVITIES GENERAL WELL BARRIER SCHEMATICS WELL BARRIER ACCEPTANCE CRITERIA WELL BARRIER ELEMENTS ACCEPTANCE CRITERIA WELL CONTROL ACTION PROCEDURES AND DRILLS Well control action procedures Well control action drills COMPLETION STRING DESIGN General Design basis, premises and assumptions Load cases Minimum design factors Completion equipment emergency shut-down system OTHER TOPICS Subsea wells (SSWs) Gas lifted wells High pressure and high temperature wells Disposal wells Multipurpose wells EXAMPLES OF WELL BARRIER SCHEMATIC ILLUSTRATIONS... 11

2 7 Completion activities 7.1 General This clausesection covers requirements pertaining toand guidelines for well integrity during activities and operations for installation of tubular and equipment in the well that will be used for transport of media to and from the reservoir and surface. The completion activity typically starts after having drilled the well to total depth and starting with cleaning of the wellformation logging program is completed and installation of completion equipment. The activity concludes with the suspension of the tubing hanger in the subsea wellhead or upon completion of the installation of the surface production tree. The purpose of this clausesection is to describe the establishment of well barriers by use of WBEswell barrier elements and additional features requiredrequirements and guidelines to execute thethis activity in a safe manner. 7.2 Well barrier schematics It is recommended that WBSs are developed as a practical method to demonstrate and illustrate the presence of the defined primary and secondary barriers in the well, see 4.2. In the table below there are a number of typical scenarios listed, some of which are also attached as illustrations. The table is not comprehensive and schematics for the actual situations during an activity or operation should be made. Item Description Comments See 1. Running and pulling of TCP guns. None 2.1 Running open end completion string. None Running closed end completion string. None 4.1 Working in well with deep set tubing plug. None 5.1 Running or pulling non shearable items through None BOP. 6.1 Pulling BOP and landing subsea production tree. None Removal of BOP and installing surface production None tree. Well barrier schematics (WBS) shall be prepared for each well activity and operation. Samples of well barrier schematics for selected situations are presented at the end of this section (5.8). 7.3 Well barrier acceptance criteria The following requirements applylist defines specific use of well barrier / well barrier elements: a) WellsAll WBEs, control lines and clamping arrangements shall be resistant to environmental loads (chemical exposure, temperature, pressure, mechanical wear, erosion, etc.). b) All injection/production wells shall be equipped with a production tree. a)c) Injection and wells that are producing or are capable of producing hydrocarbons, shall have a mechanical annular seal between the completion string and the casing/liner, i.e. production packer. e.g. production packer. All injection wells shall have the annular seal installed at a depth ensuring that the injection or any casing leak below the seal will not lead to fracturing of the cap rock or leak to shallower formations when applying METP. b)d) A SCSSVDHSV shall be installed in the completion string for all hydrocarbon wells and wells with sufficient reservoir pressure to lift fluids to seabed level (including supercharged injection formations). e) It shall be possible to install a tubing hanger plug (or a shallow set tubing plug) and a deep set tubing plug.

3 f) An ASCSSVA-annulus shall have continuous (transmitter) pressure monitoring at the wellhead with alarms during operation. c) For wells that are recompleted the condition of the remaining inner casing and the cement quality should be installedlogged. Any reduction in the completion stringwall thickness or cement quality shall be accounted for all wells 1) with a potential of hydrocarbon flow in the annulus, i.e. perforations above the production packer and injection into the annulus which might temporarily supercharge a formation; 2) where the A-annulus is used for gas lift unless there is any other downhole device that is load calculations and qualified as a well barrier in addition to what is found in the wellhead area; 3)g) when analysis and/or risk assessment shows that any hydrocarbon volume in the annulus might have unacceptable consequences if the wellhead/surface elements for maximum expected pressure and maximum anticipated differential pressures during life of well barrier is lost.

4 7.4 Well barrier elements acceptance criteria General Subclause 7.8 of this section lists the WBEs that constitute the primary and secondary barriers for situations that are illustrated Additional well barrier element (WBE) acceptance criteria The following table describes features, requirements and guidelines that which are additional to what is described in ClauseSection 15. No. Element name Additional features, requirements and guidelines Table 1 Table 4 Fluid column. Drilling BOP. During completion operations there shall be sufficient fluid available on the location to cater for any situation that might develop. Typically this will require minimum additional 100 % well volume (including riser) of the same or alternative fluid to control the well. When running completion assemblies, the drilling BOP shall be capable of shearing and sealing of/on the assembly, or one of the following criteria shall be met: a) It shall be possible to lower the assembly below the BOP by installation of a kick stand. b) It shall be possible to drop the string below the BOP. c) It shall be possible to close the BOP on a suitable joint within a kickstand distance Common well barrier elements (WBEs) There are no defined common WBEs. Table no. Element name Additional features, requirements and guidelines 1 Fluid column During completion operations there shall be sufficient fluid available on the location to cater for any situation that might develop. Typically this will require minimum additional 100 % well volume (including riser) of the same or alternative fluid to control the well. 4 Drilling BOP When running completion assemblies, the drilling BOP shall be capable of shearing the assembly and sealing the wellbore. If this is not possible one of the following criteria shall be met: a) It shall be possible to lower the assembly below the BOP by installation of a kick stand. b) It shall be possible to drop the string below the BOP. c) It shall be possible to close the BOP on a suitable joint within a kickstand distance. 7.5 Well control action procedures and drills Well control action procedures The following table describes incident scenarios for which well control action procedures should be available (if applicable) to deal with the incidents should they occur.. This list is not comprehensive and additional scenarios may be appliedincluded based on the actual planned activity, see 4.2.7activities. Item Description Comments Well influx/inflow (kick) or fluid loss while running or pulling the completion string. Running non shearable items across BOP shear rams. Running completions with multiple control lines.

5 4. Running and installation of screens Surge & Swab and well control issues 4.5 Planned or emergency disconnect of marine riser. Applies to floaters. 5.6 Drive or drift off. Applies to DP vessels Well control action drills It is recommended that drills aredrills should be executed to practice on the above well control action procedures. 7.6 Completion string design General Documented requirements for completion string design work shall be established. These shall as a minimum describe requirements as to how completion string design shall be performed. All completion, liner and tieback-strings shall be designed to withstand all planned and/or expected loads and stresses including those induced during potential well control situations. Design process shall comprise the complete well or section lifespan encompassing all stages from installation to permanent plugging and abandonment and include effects of goods deterioration of materials. Design basis and design margins shall be documented All components of the completion string including connections (i.e. tubing, packers, polished bore receptacle, nipples, mandrels, ASCSSVASV, valve bodies, SCSSVDHSV, plugs, etc.) shall be subject to load case verification. Completion string design work shall ensure that completion string is designed to suit its purpose with a known degree of safety, and identify all completion string weak points (with respect to burst, collapse, tensile and compression strength). Operator shall a) Establish documented requirements for completion string design work. The document shall as a minimum describe operator s requirements as to how completion string design shall be performed, including acceptance criteria. b) Establish documented requirements for completion string procurement, maintenance, preparation and inthe-well installation Design basis, premises and assumptions As a minimum the following data shall be used to establish the dimensioning parameters for the design process: a) Reservoirreservoir data, a)b) well data., b) Well data. c) Productionproduction or injection data., d) Fluidfluid data., e) Wellwell control actions., f) Interfaceinterface or compatibility of fluids., g) Wellwell intervention methods and treatment., h) Lifelife expectancy., i) Artificialartificial lift requirements, i)j) sand control requirements.

6 METP shall be established Load cases When designing for burst, collapse and axial load, the following load cases shall minimum be considered. This list is not comprehensive and the operator need to prepare actual and load cases applicable cases based onfor the planned activity shall be applied: Item Description Comments 1. LeakPressure testing of the completion string. Pressure testing of the completion string to METP. 2. LeakPressure testing annulus. To test tubing hanger seal,seals and production packer from above if this is not possible from below by other means. 3. Shut in of well. Based on METP. 4. Dynamic flowing conditions. Special focus on temperature effects. 5. Shut in of well by closing the SCSSV.DHSV. 6. Should check tubing collapse as a function of minimum tubing pressure (plugged perforations or low test separator pressure) at the same time as a high operating annulus (maximum allowable) pressure is present.production. Used to establish maximum allowable annulus pressure/tubing collapse in the bottom of the well.should check tubing collapse as a function of minimum tubing pressure (plugged perforations/ low test separator pressure/depleted reservoir pressure) combined with a high operating annulus (maximum allowable) pressure. Effects due to erosion/corrosion 7. Injection. Water, well killing, stimulation, fracturing. 8. Overpull. Stuck string, shear rating of pins/rings. 9. Firing of TCP guns. Applies if activation pressure governs METP. 10. Temperature effects All closed volumes with special attention to well start-up and shut-in. 11. Artificial lift requirements.. Shut-in of annulus by closing ASCSSVASV and bleeding off above a) EvacuateEvacuated annulus above gaslift valve. b) Maximum injection pressure Minimum design factors The operator shall establish a set of minimum design safety factors, describing the minimum allowable safety margin for a specific load type. The factors shall be applicable to the design work and represent the minimum acceptance criteria for the design. Minimum design safety factors shall be established for burst loads,, collapse loads, axial loads,, tension and tri-axial loads. The following design factors should apply: For deterministic calculations of loads and ratings, the below factors are suggested as guidelines: a) Burst: 1,10 b) Collapse: 1,10 c) Axial:Tension: 1,25 d) Tri-axial yield: 1,25 (pipe body and connection whichever combination is weaker) As an alternative to the above design factors, stress design or stress verification programs mightcan be employedused to demonstrate the presence of appropriate design factor(s).

7 For probabilistic calculations of loads and ratings, the probability of failure should be less than 10 3,5. The weakest point in the completion string shall be clearly identified with regards to burst, collapse and tensile strength rating. For through tubing plugs, packers and valves, the design pressure shall be minimum 1,.1 times the stated WP/maximum exposed load whichever is lower. These plugs, packers and valves shall be tested to MEDP or inflow tested Completion string equipment emergency shut-down system The following completion string equipment shall be classified as part of the installation emergency shutdown system: a) SCSSV a) ASCSSVDHSV b) ASV or any similar fail-safe-closed device (if installed). c) Production tree valves wing valve,master valves PMV, AMV. d) Production tree/wellhead valves serving chemical injection below master valves. e) Production tree/wellhead valves serving annulus gas lift valve (annulus master).. a) It shall be possible to install a tubing hanger plug (or a shallow set tubing plug) and a deep set tubing plug. 7.7 Other topics Subsea wells (SSWs) The A-annulus shall have continuous pressure recording and alarms. When establishing the maximum tubing and casing differential pressure at seabed level, one shall use the METP less the annulus pressure at this level regarded as zero (notwithout taking credit for liquid hydrostatic column from seabed to surface on the annulus side which can happen if the annulus is bled down following presence of gas) Gas lifted wells Gas lift is a method to increase oil production whereas the backpressure in the production tubing is reduced by injecting gas into the A-annulus and through the tubing at some point downhole. The use of gas lift gives large inventories of pressurised hydrocarbon gas in both surface lines and in the A-annuli. Release of these inventories is a substantial topsides hazard to platform. All platform wells shall have an ASV installed in the A-annulus that limits the amount of hydrocarbon gas release in the event of damage to the production tree, wellhead or surface lines. Based on risk assessment, alternative solutions may be utilized if the same safety level or higher can be achieved. An alternative solution can be a combination of a qualified downhole valve (qualified as a WBE) and a fail-safe-closed device in the wellhead or close to the surface tubing hanger. The alternative solution shall reduce the potential release of hydrocarbon gas compared to an ASV solution. A gas lift injection valve (a WBE) can be used as an alternative to an ASV in subsea wells. The following additional requirements apply: a) An analysis shall be performed to assess the risk of release of hydrocarbon gas to the surroundings (air, water column) if the wellhead/production casing barrier elements are lost. The total risk for the installation shall be included in the analysis. b) Intermediate casing and formation/cement shall act as secondary well barrier elements against gas lift pressure unless analysis and/or risk assessment shows that any release of hydrocarbon volume from the annulus do not have unacceptable consequence if the wellhead/production casing is lost.

8 c) Gas should only be introduced to the casing to tubing annulus that has gas tight premium connections that are properly made-up and tested in order to affect as a gas tight seal. d) B-annulus shall have continuous pressure monitoring with alarms. For subsea wells the B-annulus shall be designed to withstand thermal induced pressure effect (APB) High pressure and high temperature wells Specification and qualification criteria for equipment and fluids to be used or installed in a HPHT well shall be established, with particular emphasis on: a) dimensional stability of the well as a function of temperature and pressure, b) sealing capability of metal to metal seals as a function of well bore fluids, pressure and temperature, c) stability of explosive and chemical perforating charges as function of temperature/pressure exposure time, d) clearance and tolerances as function of temperature and differential pressure exposure, e) deterioration of elastomer seals and components as function of temperature/pressure exposure time and wellbore fluids. f) packer fluid selection and design including hydrate prevention Disposal wells Disposal wells are designed and used to inject liquids, slurries brines or gases into dedicated formation for disposal. The injected media shall be contained within the dedicated formation without deteriorating or penetrating the formation barrier/cap rock. Wells injecting at a pressure greater than the formation fracture pressure (minimum horizontal stress) at the injection depth, the following apply: a) the production packer shall be set below the cap rock, b) the cement shall be logged and have confirmed bonding from the top perforation and up to 200mMD above top of reservoir, c) it shall be documented that the injection will not result in a reservoir pressure exceeding the strength of the cap rock Multipurpose wells A multipurpose well is defined as a well that has transport of media to or from a formation interval via the A- annulus in addition to transport through the tubing. The following requirements and guidelines apply: a) A-annulus shall 1) have continuous pressure monitoring; 2)a) be equipped with an ASCSSV, see 7.3 c. ASV b) B-annulus shall have continuous pressure monitoring with alarms. For SSWssubsea wells the B- annulus (production and intermediate casing) shall be designed to withstand the thermal pressure build-up if. If this is not possible, otherwise an acceptablea pressure management system shall be implemented. If the production casing is not cemented into the intermediate casing, the exposed formation shall have a documented ability to withstand a leaking production casing scenario. c) The intermediate casing shall be 1)c) designed as a production casing for both planned and A-annulus fluid exposure during the well life; 2) designed to withstand METP; 3) pressure tested to METP prior to running production casing. d) Production casing shall be designed as production tubing for both planned and well fluid exposure during the well life. e) Production casing / liner cement should be cemented into the intermediate casing unless it can be documented that the formation can withstand METP (production casing leak scenario).

9 f) Annulus control lines and clamping arrangements shall be resistant to environmental loads (chemical exposure, temperature, pressure, mechanical wear, erosion, etc.) High pressure and high temperature (HPHT) wells Specification and qualification criteria for equipment and fluids to be used or installed in a HPHT

10 Examples of well shall be established, with particular emphasis on a) dimensional stability of the well as a function of temperature and pressure, b)a) sealing capability of metal to metal seals as a function of well bore fluids, pressure and temperature, c)a) stability of explosive and chemical perforating charges as function of temperature/pressure exposure time, d)a) clearance and tolerances as function of temperature and differential pressure exposure, e)a) deterioration of elastomer seals and components as function of temperature/pressure exposure time and wellbore fluids.

11 7.8 Well barrier schematic illustrations Item Description Comments See Running and pulling of TCP guns. None Running open end completion string. None Running closed end completion string. None Working in well with deep set tubing plug. None Running or pulling non shearable items through BOP. None Pulling BOP and landing subsea production tree. None Removal of BOP and installing surface production tree. None

12 NORSOK Standard D-010 Rev. 4, Running open end completion string Well barrier elements Primary well barrier See Table Comments 1. Fluid column 1 NORSOK standard 13

13 NORSOK Standard D-010 Rev. 4, 2012 Secondary well barrier 1. Casing cement Casing 2 3. Wellhead 5 4. High pressure riser 26 If installed. 5. Drilling BOP 4 Note None NORSOK standard 14

14 NORSOK Standard D-010 Rev. 4, Running nonshearable items through BOP NORSOK standard 15

15 NORSOK Standard D-010 Rev. 4, 2012 Well barrier elements Primary well barrier See Table Comments 1. Fluid column 1 Secondary well barrier 1. Casing cement Casing 2 3. Wellhead 5 4. High pressure riser 26 If installed. 5. Drilling BOP 4 Minimum one pipe or annular preventer shall be able to seal the actual size of the non-shearable item. 6. Completion string Tubular string safety valve 40 Note None NORSOK standard 16

16 NORSOK Standard D-010 Rev. 4, Pulling BOP and landing subsea production tree NORSOK standard 17

17 NORSOK Standard D-010 Rev. 4, 2012 Well barrier elements Primary well barrier See Table Comments 1. Production packer 7 2. Completion string 25 Between production packer and plug. 3. Deep set tubing plug 6 Secondary well barrier 1. Casing cement Casing 2 3. Wellhead 5 4. Tubing hanger Completion string 25 Above SCSSV.. 6. SCSSV 8 A debris plug shall be installed in the tubing hanger production bore if the upper well barrier is a SCSSV. 7. Tubing hanger plug 11 Plug in annulus bore. Note Non NORSOK standard 18