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Bp Casing Design Manual
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Reload to refresh your session. Discover everything Scribd has to offer, including books and audiobooks from major publishers. Start Free Trial Cancel anytime. Report this Document Download Now save Save Casing Design Manual - BG (2001) For Later 100 (21) 100 found this document useful (21 votes) 22K views 51 pages Casing Design Manual - BG (2001) Uploaded by PetroleumEngineering Description: Casing Design Manual - BG (2001) Full description save Save Casing Design Manual - BG (2001) For Later 100 100 found this document useful, Mark this document as useful 0 0 found this document not useful, Mark this document as not useful Embed Share Print Download Now Jump to Page You are on page 1 of 51 Browse Books Site Directory Site Language: English Change Language English Change Language. Report this Document Download Now save Save Casing Design Manual 1.docx For Later 100 (1) 100 found this document useful (1 vote) 236 views 1 page Casing Design Manual 1.docx Uploaded by Adrien Ofthestone Description: schlum Full description save Save Casing Design Manual 1.docx For Later 100 100 found this document useful, Mark this document as useful 0 0 found this document not useful, Mark this document as not useful Embed Share Print Download Now Jump to Page You are on page 1 of 1 Search inside document Scribd members can read and download full documents. Your first days are free. Continue Reading with Trial Share this document Share or Embed Document Sharing Options Share on Facebook, opens a new window Share on Twitter, opens a new window Share on LinkedIn, opens a new window Share with Email, opens mail client Copy Text Footer Menu Back To Top About About Scribd Press Our blog Join our team. Browse Books Site Directory Site Language: English Change Language English Change Language. Some features of this site may not work without it.
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During manyThe current casing design atThe injection pressure isThe ESIPC would provide a good cement jobThe C-Flex isThe Cement Assurance Tool is just an extra safety inThis barrier element isIt has to beThe corresponding dual bottom-top wiper plug set has to be reinforced as. Severe circulation losses led to pumping of a gunk pill. This plugged the drill string leading to a shut-in wellhead pressure. A well control operation stabilized the well, which was eventually sidetracked. The review found that the casings had sufficient strength in burst and tension and collapse. It is, however, recommended to consider more realistic design scenario. Severe losses indicate that a gas filled casing scenario should be appliad rather than a kick margin for burst design. This will require a higher casing test pressure. Likewise, circulation losses gives more severe loading than base-oil filled casing for collapse design. However, in the subsequent sidetrack (A-08 C9 more severe design scenario were used. The risk worksheet cover normal losses, but does not identify total losses in the reservoir as a potential risk. A strategy for combating lost circulation in the reservoir should be developed. The decision to continue to circulate the well after a positive flow check, and the unsuccessful pumping of a gunk pill should be re-visited, with a view to clarifying what procedures would be applicable in a future similar situation. 3 1. Project Description The objective of the project is to investigate the methodology for casing design for several operating companies in Norway. The present report focuses on BP. The project will evaluate the design manuals, the methodology for data collection, the quality and the use of these in the course of the well design. The background for the project is that the PSA has observed cases where the casing design was the limiting factor for the well at several operating companies.
Because one expects a number of HPHT wells in the near future, the design basis each operator uses is identified to search for improvements. A review of the operational aspects of the incident has also been performed. 4 2. Review of BP’s casing design procedures 2.1 BP’s governing documentation After the merger a few years ago between BP and Amoco, the documentation has been revised. References 1 through 5 identify the manuals related to well construction. The overall impression is a set of manuals that are modern, updated and of high quality. The manuals are in electronic format, allowing for yearly updates. In the following we will review ref. 3 which is the Casing Design Manual. Part 2: Quick Guide contains the following subchapters: 1. Introduction 2. Data needed before design 3. Design summary 4. Casing setting depths 5. Collapse design 6. Burst design 7. Tension design 8. Tri-axial design 9. Buckling and compression 10. Casing wear 11. Temperature 12. Special design cases 13. Reliability 14. Connection selection 15. Materials selection 16. Kick tolerance This part is a compact reference for well designers familiar with the remainder of the manual. References are provided to details defined in other chapters. The Quick Guide provides a good summary. We will not discuss this further, but provide comments to the chapters to follow. Part 3: Detailed Manual contains the following subchapters: 1. Introduction 2. Data needed before design 3. Casing design software in BP Amoco 4. Casing setting depth guidelines 5. Collapse design criteria 6. Burst design criteria 7. Tensile design criteria 8. Tri-axial design analysis 9. Buckling and compression design considerations 10. Casing wear 11. Temperature considerations 12. Special design cases 13. Casing design reliability 14. Connections 15. Corrosion 16. Kick tolerance Part 3 is the major part of the manual and contains a lot of information.
www.corwell.co.uk/userfiles/files/casio-7500-manual.pdf
Although different design criteria can be applied, the manual reflects current industry understanding. Most of these are used by many other operating companies and are considered industry standard. A discussion about each program is also presented, addressing limitations and giving practical advice. Subchapter 4: Casing Setting Depth Guidelines is a key chapter in the design process. The initial setting depth based on pore and frac pressures is the start of the design. The chapter further addresses mud weight, hole inclination and other important factors. The chapter gives a good overview over the well design process. The following statement is reproduced from this chapter: “Sensitivity studies should be considered to identify the contingency provisions required to accommodate pore or fracture pressures during drilling which differ from those assumed during design. Kick tolerances which may be acceptable for seat selection are not an acceptable basis for mechanical burst design.” Subchapter 4 further presents methods to derive fracture gradient and overburden prognosis. Methods by Daines, Hubbert and Willis, Mathew and Kelly, Pennebaker, Eaton, MacPherson and Berry and Zamora are recommended. These are all correlation methods from the 1970’s and 1980’s. Daines method has in particular been popular to establish fracture prognosis in vertical wells. Most wells today are deviated. Also, in-situ stress analysis has proven useful. It is recommended to consider these newer approaches for fracture gradient predictions. The inversion method derived by Aadnoy(ref. 6) has in particular provided good results. Reference 7 presents alternative modeling methods. Subchapter 6 covers burst design. It is stated that: “Local regulatory agencies, e.g. MMS in the Gulf of Mexico, may impose specific local criteria which differ from those in the manual.
Nevertheless wherever possible, casing design in BP Amoco should: - Provide casing stronger in burst than the fracture pressure of exposed formation beneath the shoe. - Take account of the possibility of a hydrocarbon column to the wellhead.” The first condition implies that a weak point in the well should never be beneath the wellhead, but below the casing shoe, a sound approach. Reference 7 discusses this requirement in 7 detail. The second comment about gas(oil) filled casing will be addressed in the discussion of well A8B later in this report. Also the burst design chapter discusses the external pressure profiles for burst load design. In summary, the following conditions are given(our short version of the conditions): -External pressure equal to pore pressure in cemented intervals. -External pressure equal to mud mix fluids (i.e. hydrostatic of water for waterbased mud and hydrostatic of base oil for oil based mud). -Mud density for short time applications. The classical back-pressure used in the oil industry is the pressure caused by water. Because water is the only mobile phase, and particles settles out over time, this very conservative criterion is used by many operators. However, for critical wells the mud weight is used as a short time scenario. It should be stated that the back-pressure issue is not fully resolved throughout the industry. Subchapter 10 covers casing wear. Their treatment includes practical experience, experimental tests on casing, tool joints and mud. They also state the well known fact that the theoretical solutions for wear are not particularly good. Casing wear reduces the burst and collapse strength of the casing strings. Equations are presented to perform these calculations.
Additional comments that could be included are: 1) Tools that measure casing wear have a given resolution, and may not give a correct picture, and, 2) in critical wells it may be advisable to pressure test casings if there is uncertainty about the degree of casing wear. Subchapter 13 covers casing design reliability. It is interesting to observe the following statement: “The most important parameter in determining the reliability and success of a casing design is the pore pressure. This means drilling engineers must work closely with all supporting groups to determine pore pressure confidence levels and ensure that all parameters impacting pore pressure predictions have been addressed.” This demonstrates the fundamental coupling between various elements of the well design. Part 5 presents a design example. This worked example serves well as a guide as many important elements are included. 2.2 Discussion of BP’s Casing and Tubing Design Manual. The manual is modern and a document of high quality. The manual reflects the understanding and emphasize the four key parameters: -the pore pressure -the fracture pressure -the density of the formation fluid 8 -the back pressure on the casing We did not find any errors in the manual, but have supplied a few comments as seen from an outside observer. BP Amoco may consider including these. The manual is very comprehensive and well organized. Such a manual should also be accompanied by a competence requirement for the personnel using it. The quality of the design still depends on the competency of the well designer and the quality of the design verification. The test showed no flow. Drilling ahead approximately 62 m from the shoe, total losses were encountered. The loss rate was gradually reduced as the rig attempted to keep the hole full by filling it with premix and base oil and then eventually seawater. The well was then stabilized by placing a total of 65 bbls LCM in the open hole section.
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The drill string was round-tripped to lay down the radioactive source. At the shoe a flow check gave 10 bbls gain in 25 min, suspected to be ballooning. The well was circulated for 15 min before a new flow check gave 2 bbls gain in 5 min. Circulation with the well open was performed for 1 hour until a sharp increase in returns was observed. The well was shut in on the annular preventer with SIDPP of 0 psi and SICP of 200 psi. Attempts were made to stabilize the well by circulating out gas through the choke. Two LCM pills were displaced in attempt to cure the losses without success. Casing pressure was still rising slowly. It was then attempted to kill the well using 9.0 ppg water based mud. During the circulation, dynamic losses were experienced and the returns contained crude oil. After circulating the full well, the casing pressure was 534 psi while the drill pipe pressure was 450 psi. Another LCM pill was displaced down and squeezed to cure the losses, but unsuccessful. It was then attempted to kill the well by circulating 10 ppg mud around through the choke. Due to high gas peaks and unstable returns the well was shut in and it was attempted bullhead the gas on annulus side by seawater and 10 ppg mud. Gas readings were still high and a gunk pill was pumped through the drill pipe to plug off the open hole. The gunk pill plugged off the drill pipe and the ability to circulate the well was lost. The casing pressure continued to rise leveling off at 800 psi. An attempt to pressure test the annulus broke down the formation and gave injectivity at 850 psi. The casing pressure 10 Quote from ref. 8, continued: was still rising so the annulus was bullheaded with 2 annulus volumes of seawater making the casing pressure to drop to 0 psi. To stem the losses, a 54 bbl LCM pill was bullheaded down and squeezed into the formation. The well was then shut in and monitored showing a rapid pressure build-up on the casing side. At the same time it was started to lubricate in 15.
0 ppg mud to increase the hydrostatic head on the annulus side, and a mix of free gas and 9-11 ppg mud was bled off. While continuing to bleed off and lubricate on the annulus side, wireline equipment was rigged up on top of the drill string. Preparations were then made to kill the well with 14.0 ppg mud. After circulated the well to even mud through the choke, the annular was opened and the well circulated conventionally. A flow check was performed and the well was static. 3. Conclusions Root cause of lost circulation. These fractured hard grounds, likely to be found in the crestal area, may act as flow units and free gas may accumulate in the fractures, which will allow for easy flow of drill fluid even at low-pressure differentials. Cores from the hard grounds in a similar well (F-11) prove large voids, which support the current failure explanation. (see details in appendix 3) The subsurface team will use some more time to look at other possible causes. They will check details on the plot (appendix 4) to see if there are other reasons for the loss problem. This information will be used for future planning on similar wells on Valhall Crest. Well Control root cause The well control incident initially developed on the trip to lay down the radioactive source, but escalated when gunk plugged the drill string and circulation was no longer possible. From the actions taken in the initial phases of the incident, BP seem to have lacked a plan for dealing with lost circulation. Total losses were first encountered at 0315 hrs 9.12.2003, but the first lost circulation pill was pumped at 1000 hrs on the same day, after losing over 4000 bbl of fluid (oil based mud, base oil, and sea water). This observation appears to be confirmed by the risk worksheet listing potential risks with the well. Destabilise natural fractured rock (around faults and in potential problem area) with the risk description including ballooning with losses while drilling and flow back with the pumps off.
The mitigation strategy was to limit the maximum ECD and to follow the mud weight increase set out in the drilling fluid BOD (basis of design). Combating losses was not addressed Risk 3601. Unexpected faults. Poor seismics in the upper 1000 m may make it difficult to identify faults, leading to the possibility of drilling unexpectedly through a fault. The mitigation here was to specify in detail how to weigh up, and to avoid weighing up too quickly. Combating losses was not addressed Please note that the two risks above refer to the overburden section, not the reservoir. The incident described in this report is the first time breathing in the reservoir has been seen. 13 Risk 3610. Loss of circulation during running casing and cementing. This does not address total losses while drilling Risk 3625. The mitigation strategy was to ensure sufficient mud reserves available by storage on boats so that drilling without returns would be possible. This risk is addressed at the 12 ?” hole section and, as such, does not cover the 8 ?” hole section. The mitigation strategy certainly does not seem to have been in place for this incident. Risk 77. Mud losses penetrating the Tor with drilling string. This again addresses losses in the 12 ?” section with the mitigating strategy to have a gunk system ready for use. Gunk was first pumped on this incident about 5 days after losses were seen. Losses did in fact come in the Tor formation, but not while drilling down the liner, and 62 m below the shoe after the mud weight had been cut back. Although the internal BP report indicate that the reservoir drilling risk evaluation identified losses was a risk, and contingency plans made, the risk worksheet does not confirm this. Although the losses were stopped and a trip to change the BHA and remove the radioactive source was made successfully, well integrity was not sufficient, and losses were again induced, finally leading to an influx being taken.
Activities that should be instigated should include investigation into the best total loss circulation combating strategy, with identification of applicable LCM materials (including gunk) and combination of same, together with procedures for use of them. The gain seen during the flow check after the trip to change the BHA was interpreted as ballooning, which in this case may have been erroneous. In hindsight, a full circulation over the choke at constant bottom hole pressure would have been advisable to confirm the gain was, in fact, ballooning. Most well control policies demand the well be shut in if a gain is seen at a flow check. Due to the loss problem, it is perhaps understandable that circulating over the choke was not done. This again goes back to evaluation of applicable strategies for combating loss circulation. The strategy chosen led to the use of the gunk pill, which was identified as a mitigating strategy in the 12 ?” section. The result of this action, was possibly the worst possible. The drill string was blocked during this process, and the losses were not cured. This worsened the situation significantly. Tagged shoe at 2993 m. Drilled shoe Drilled out shoe. Annulus entirely full with base oil. No decrease in loss rate. Total losses 1412 bbl mud, 341 bbl base oil 7.12.03 8.12.03 9.12.03 Problems with Hitec Cyberbase system. Lost 2.5 hrs plus more problems off the critical path FIT 900 psi at 2437 m TVD with 8.4 ppg mud (Check!!) 7 hrs downtime with Cyberbase system Differential sticking indications Mud motor stall out. Packed off annulus? Base oil to formation 15 Date 10.12.03 11.12.03 Description Comments Switched to filling annulus with sea water. At 2132 m losses suddenly increased. Washed down to 2736 m. Washed down to casing shoe at 2994 m. Got LCM in returns over shaker. After 640 bbl gas increased. Gas up to 12. Shut in well. Circulated gas out from BOP. Resumed circulating over choke, 120 gpm, DP constant 180 psi, CP 40 psi.
Circulated across BOP to monitor losses. Pressure dropped to 0 psi in 8 min Circulated over BOP to monitor losses. Bullheaded 1050 bbl at 1100 psi Circulated over BOP to monitor losses. Pumped 65 bbl of LCM down the string. Losses reduced while pumping LCM out of string. Lost 17 bbl under displacement Flow checked well. Gained 2 bbl in 4 min. 12.12.03 Hesitation squeezed 60 bbl LCM pill Observed pressures. Level in DP dropping Injectivity test. Pumped down string with cement unit to keep string open. No losses Circulated well to 10 ppg mud. Shut in well Bullheaded annulus with 920 bbl SW. Problems coming out of pipe Gunk in pipe. Re-ran same. Perforated and confirmed communication. Continue lubricating mud into hole Allowed SICP to increase to 1900 psi.So please help us by uploading 1 new document or like us to download: We are a non-profit group that run this website to share documents. We need your help to maintenance this website. If that document is field-wide, a separate document shall, when appropriate, stipulate where a specific well design deviates from the field-wide basis of design. 1.2A casing and tubing design shall be performed for all wells and should incorporate foreseeable life-of-well requirements and abandonment. Where wells are to be produced, tested, stimulated, injected or modified, a design check shall be performed for the existing configuration, unless as part of the SPU assurance process a previous design is demonstrated to be adequate. Design Standard 1.3The requirements contained within the BP Tubular Design Manual (BPA-D-003) shall be applied for both the tubing and casing program basis of design. The basis of design will address parameters within which it is acceptable to plan further wells in a programme, campaign or area without further detailed design. When these parameters are exceeded, a detailed reassessment of the design is required. Tools and Design Data 1.
4Casing and tubing design shall be performed using the BP approved casing design software and methods as identified in the BP Tubular Design Manual. Every component shall also be in good condition, and all equipment should be suitable for expected service life.1.6Casing and tubing design software are safety critical.1.7Casing and tubing designs shall be subject to assurance review as a minimum shown in Table 1 in this ETP.1.8A minimum set of design loads, including setting depth, burst, collapse, tension and triaxial considerations for both the tube body and connection, is defined in the BP Tubular Design Manual. Designs governed by loads outside those listed in the BP Tubular Design Manual shall be subject to review as in Well Category 3 in Table 1. 1. All casing and liners shall be designed to withstand reasonably foreseeable well control burst loadings. The starting point for well control burst loading shall be gas to surface from casing shoe, or lower open hole fracture pressure. Casing designs using lesser well control loadings not appearing in the BP Tubular Design Manual as acceptable alternatives shall be subject to review as per Well Category 2 in Table 1. 2. Casing designs shall include definition of the well control scenarios they accommodate and their rationale based on subsurface information, local experience and operational well control capabilities. Welding operations on other grades of pipe will require specific qualifications and procedures per GP 18-01. A revised design evaluation shall be completed, should such an occurrence be contemplated. This Group Practice (GP) replaces the relevant parts of the Drilling and Well Operations Policy BPA-D-01. These components include the casing and production tubing and connections. This GP references the mechanical load scenarios that should be addressed and the minimum design factors that should be applied during the design phase.
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