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Home My WebLink AboutO 006~ r INDEX OTHER ORDER N0.6 1. September 23, 1980 Exxon requests that regulation 20 AAAC 25.035 Blowout equipment be revised 2. October 24, 1980 Exxon ltr re: Variance to 20 AAC 25.035(c)(2) 3. November 14, 1980 Notice of hearing, affidavit of publication 4. December 17, 1980 Transcript of Hearing 5. December 15, 1980 Proposed changes to Alaska Administrative code Title 20, 20 AAC 25.035 6. December 22, 1980 Shell re: ltr proposed amendment 7. ---------------------- copy of old regulation 8. January 16, 1981 affidavit of notice of adoption of regulation and affidavit of oral hearing 9. January 23, 1981 Attorney General's Office comments OTHER ORDER #6 (no order issued) r _,._ r The attached one page of regulations, dealing with Blowout ~3GEOL.__ Prevention Equipment are hereby adopted and certified to be a~STATTEC correct copy of the regulations which the Alaska Oil and Ga ~STATTEC Conservation Commission amends under authority vested by AS ___I __--- 31.05.030 and after compliance with the Administrative Proce=~°'~FR:._ duce Act (AS 44.62), specifically including notice under AS 44.62.190 and 44.62.200 and opportunity for public comment. under AS 44.62.210. - ~o~ ~~ ~ COMM"' RES ENG 1 ENG 2 ENG ORDER AMENDING REGULATIONS OF 3ENG ALASKA OIL AND GAS CONSERVATION COMMISSION 4ENG _ 1 GEOL ~ 2 GEOL This action is not expected to require an increased appropriation. This order takes effect on the 30th day after it has been filed by the lieutenant governor as provided in AS 44.62.180. DATE : ~/~G~~~ An orage, Alaska le Hamilton Chairman/Commissioner. t ~ Lonnie ~. Smith Commit Toner /~` ~ ,~ Harr W. Kug r Commissioner I~ Terry Miller , Lieutenant Governor for the. State of Alaska, certify that on January 23 ,1981 , at 4:15 p .M., I filed the attached regulations according to the provisions of AS 44.//6/2.0\4\0~-- 44.6 120. / A Effective ~eDr~~r~ ~~ ~~~~ . ) Register ~7~ ~-A~~ / / ~/ . ) eutenant Governor.. Alaska 0i1 & G~ ~ Cons. Comm(ssinrt Anclroraga • ~ Register 77, April, 1981 MISCELLANEOUS BOARDS, COMMISSIONS 20 AAC 25.035 The following. parts of 20 AAC 25.035. BLOWOUT .PREVENTION EQUIPMENT are amended to read as follows: (c) Blowout Prevention Equipment: (1) before drilling below the surface casing, and until completed, a well must have remotely controlled BOP's; the working pressure of the BOP's and associated equipment must exceed the maximum potential surface pressure, except that the annular preventer need not have a working pressure rating greater than 5000 psig; -.the BOP stack arrangements must be as follows: (A) API 2M, 3M, and 5M stacks must have at least three preventers, including -one equipped with pipe rams that fit the size of drill pipe, tubing, or casing being used, one with blind rams, and one annular type; (B) API lOM and 15M stacks must have at least .four preventers, including two equipped with pipe rams with at least one fitting each size of drill pipe, tubing, or casing being used, one with blind rams and one annular type; (2) information submitted with Form 10-401 must in- clude the maximum downhole pressures which may be encountered, the maximum potential surface pressures, the criteria used to determine these pressures, and a well-control procedure which indicates how the preventers will be used for pressure control operations if the maximum surface pressures should exceed the rated working pressure of the annular preventer; (5) the BOP equipment must include a drilling spool with side outlets (if not on the blowout preventer body), a minimum three-inch choke line and a minimum two-inch choke manifold, a kill line, and a fillup line; the drilling string must contain full opening valves above and immediately below the kelly during all circulating operations using the kelly, with the necessary valve wrenches conveniently located on the rig floor; and (6) two emergency valves with rotary subs for all connections in use and the necessary wrenches must be conveni- ently located on the drilling floor; one valve must be an inside spring-loaded or flow activated type; the second valve must be a manually operated ball type, or equivalent valve. (Eff. 4/13/80, Reg. 74; am 2/22/81, Reg. 77) Authority: AS 31.05.030 NOTE: Replaces portions of pages 7 and 8 of the Regulations. mnors =WMA .<.~ MEMORA~UM To: Hoyle H. Hamilton Chairman Alaska Oil and Gas Conservation Commission State of Alas DATE FILE NO TELEPHONE NO FHOnn: WILSON L. CONDON SUBJECT ATTORNEY GENERAL By: Arthur H. Peterson Assistant Attorney General and Regulations Attorney January 23, 1981 J-99-08~-81 465-3686 Commission regula blowout preventio ment (20 AAC 25.0 (2), (5), and (6) ~_,_~,~~ 11 ENG n '~ ~~,n n on P- Under AS 44.62.060, we have received your amendments of 20 AAC 25.035(c)(1), (2), (5), and (6), and approve them for filing by the lieutenant governor. A duplicate original of this .memorandum is being furnished the lieutenant governor, along with your amended regulation and related documents. In accordance with AS 44.62.125(b)(6), some corrections have been made in this regulation, as shown on the attached copy. Your adoption order states that this action is not ex- pected to require an increased appropriation. Therefore,. AS 44.62.195 does not require a fiscal note.. In addition, since no increased appropriation will be required, it is the opinion of this department that your failure to comply with AS 44.62.200(a)(5) by summarizing the fiscal infor- mation in your public notice is of no significance. AHP:bj 1 cc w/enc.: Jeffrey Lowenfels Assistant Attorney General Anchorage RECEIVE Alaska Oil & Gay Cons. Commission Anchorage 02-OOlA(Rev.10/79) • • Register , 1981 MISCELLP,NEOUS BOARDS, OONIl~4ISSIONS 20 AAC 25.035 The following parts of 20 AAC 25.035. BLOWOUT PREVENTION .EQUIPMENT are amended to read as follows: ~ c) Blowout Prevention Equipment: (1) before drilling below the surface casing, and until completed, a well must have remotely controlled BOP's; the working pressure of the BOP's and associated equipment must exceed the maximum potential surface pressure, except that the annular preventer need not have a working pressure rating greater than 5000 psig~ '~ie BOP ..stack arrangements `' ~~ as fol l~~rs ~ks~'` (A) API 2M, 3M, and 5M stacks must have at least three preventers, including one equipped with pipe rams that fit the size of drill pipe, tubing, or casing being used, one with blind rams, and one annular type; (B) API lOM and 15M stacks must have at least four preventers, including two equipped with pipe rams with at least one fitting each size of drill pipe, tubing, or casing being used, one with blind rams and one annular type j (2) information submitted with Form 10-401 must in- clude the maximum downhole pressures which may be encountered, the maximum potential surface pressures, the criteria used to determine these pressures, and a well-co trol procedure which indicates how the reventers will be sT±-~-~:~.~. P q _.._,for pressure control operations if the. maximum surface pressures should exceed the rated working pressure of the' annular preventerj (5) the BOP equipment must include. a drilling spool with side outlets (if not on the blowout preventer body), a minimum three-inch choke line and a minimum two-inch choke manifold, a kill line, and a fillup line; the drilling string must contain full opening valves above and immediately below the kelly during all circ~.zlating operations using the kelly, with the necessary valve wrenches conveniently located on the rig floor; and (6) two emergency valves. with rotary subs for all connections in use and the necessary wrenches must be conveni- ently located on the drilling floor; one valve must be an inside spring-loaded or flow activated type; the second valve m st be a manually operated ball type, or equivalent value. ~am. / /81, Reg. ) EF4. ~ t3 ~0, ~ • ~~, Authority : AS 31.0 5. 0 30 RECEIVED FTIRro-I �im ~ • STATE OF ALASKA ) ss, THIRD JUDICIAL DISTRICT ) AFFIDAVIT OF NOTICE OF ADOPTION OF REGULATION I, Hoyle H. Hamilton, Chairman/Commissioner, of Alaska Oil and Gas Conservation Commission, being sworn, depose and state the following: As required by AS 44.62.190, notice of the proposed amendment of Title 20, AAC 25.035 has been given by . (1) being published in a newspaper or trade publication, (2) .being mailed to interested persons, (3) being mailed or delivered to appropriate state officials, (4) being furnished to the Department of Law, (5) being furnished to incumbent State of Alaska legisla- tors and the Legislative Affairs Agency. DATE : ~/l~~~~ anchorage H e Ha i ton Ch irman/Commissioner SUBSCRIBED AND SWORN TO before me this i~~ _t~ day of ~,~:~,~;.titi 1981. ~ Notary Phi lic i%~4- and for Alaska My commission expires : S-`I-~/ ~ • STATE OF ALASKA ) ss. THIRD JUDICIAL DISTRICT ) AFFIDAVIT OF ORAL HEARING I, Hoyle H. Hamilton, Chairman/Commissioner of the Alaska Oil and Gas Conservation Commission being sworn, depose and state the following: On December 17, 1980 at 9:30 AM, in the Municipality of Anchorage Assembly Room in Anchorage, Alaska, I presided over the public hearing held in accordance with AS 44.62.210 for the purpose of taking testimony in connection with the amendment of Tit1e,20, AAC 25.035. DATE : ~/~G/~~ -~ Anchorage H e H. Hamilton, Chairman/Commissioner SUBSCRIBED AND SWORN TO before me this ~ day of ~ z~.~~~.w _, 1981. ` ~~ ~4 ~ . ~~ ~~= 1 `~ Notary Ptt is in " nd fog' A~-aska My Commission expires: -_~-.~~ ~ 7 ~~~~ YJ r f`~~'(~c1 Blowout_ Prevention Equipment:_ (1) b~= re drilling below the sL ice casing, a well ~~<jjmust have a mini.;., ..~ of three remotely control,.. sd BOP's, including ~ one equipped with pipe rams that f it the size of drill pipe; or ~~ ~Ln,,-~~ casing being used, one with blind rams, and -one annul«r type; (2) the working pressure of any BOP and associated n. `' ' f w ,~.~ fib,, : equipment must exceed the maximum surface pressure to which they may be subjected; information;subr-itted with Form. 10-401 must in- clude the anticipated downhole pressures to be encountered, the maximum surface pressures to which. the BOP equipment may be .s bjec.ted, and the crte;~*ia%used to determine these pressures; '~/ (3) the hydraulic actuating system used must provide v sufficient accumulator capacity to supply 1.5 times the volume of hydraulic fluid necessary to close all BOP equipment; the. system ~/~ must also be capable of maintaining a minimum remaining pressure of 200 psig above the required precharge pressure when all BOP's are closed with the primary power source shut off; an accumulator backup system, supplied by a secondary power source independent of the :primary power source, must be provided with sufficient capacity to actuate all BOP equipment; (4) in addition to the primary controls on the accumu- lator equipment unit, at Ieast one operable remote .BOP control station. must be provided; this control' station must be in a readily accessable location on or near the drilling floor; a device to avoid unintentional closure must be provided on all emote blind ram closing controls; (5) the BOP equipment must include a drilling spool. with minimum two.-inch side outlets (if not on the blowout.preven- ter body),. a minimum three-inch choke line and minimum two-inch choke:.manifold, a kill line., and.. a fillup line.; the drilling. string must contain full opening valves above and immediately below the kelly during all circulating operations using the kelly, with the necessary valve wrenches conveniently located on the r.ig floor; and (6) two emergency valves with rotary subs for all connections in use. and the necessary wrenches must be conven- iently located on the drilling floor; one valve must be an inside BOP of the. spring-loaded type; the second valve must be of the manually operated ball type, or equivalent valve.. (d) Testing: (1) all ram-type BOP's, kelly valves, emergency valves and choke manifolds must be tested to the ra'~ed working pressure or to the maximum surface pressure as required to be submitted in (c)(2) of this section; annular preventers must be tested to not less than 50 percent of the rated working pressure; these tests must be made when the BOP equipment is installed or changed and at least once each week thereafter; test results must be recorded as required by sec. 70(a)(1) of this chapter; (2) to insure that minimum standards are achieved, the operator shall perform the recommended tests for bOP closing units specif led in sections 5A and 5B of API RP 53; and (3) sufficient notice of certain BOP equipment tests must be given so that a representative of the commission can witness. these tests; these tests will be specif led in the drill- ing permit or by notice to the operator. (e) BOP equipment for cable tool drilling activities must have prior commission approval and must be in accordance with good established practice with all equipment in good operating condition at all times. (Eff. 4/13/80, Reg. 74) Authority: AS 31.05.030 ~6 ,, Shell Oil Company ``~`"~` 601 West Fifth Avenue • Suite 810 Anchorage, Alaska 99501 '' j,. December 22, 19£30 Pair. L.C. Smith, Commissioner State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Lonnie: ~aNS•~~tE ~~r1Z Thank you for sending us a copy of the proposed amendment of Title 20, AAC 25.035. I have reviewed this material and do have some comments that I would like to submit for your consideration. Title 20 AAC 25.035 (c)(1)(A) and (B) contains wording that might be interpreted to mean that casing rams are required to be in place when casing is run. I agree in principle that casing rams provide an added safety factor. However, in order to install casing rams, it is nec- essary to open up the blowout preventer, thus breaking the body seal. After installing the casing rams, the preventer must be retested to ensure the integrity of the body seal and the rams. All of this work must be done while the drill pipe is out of the hole and preparations are being made to run casing. In most cases, hole conditions, from a well control standpoint, are such that this work can be accomplished with no significant risk. However, there are those instances in which the control of a well can be jeopardized to a greater degree by taking the extra time to install and test casing rams and by breaking a preventer seal at a rather critical point in the operation. I would suggest, therefore, adding wording to Title 20 AAC 25.035 (c)(1) as follows: Casing rams should be used when running casing. It is recognized that in certain situations, the safety of the well may be jeopardized by changing rams preparatory to running casing. In those cases where it is decided casing rams should not be installed, a crossover from. drill pipe to casing and drill pipe of sufficient strength to support the casing weight shall be on the rig floor ready for use. 'i >1. `' Mr. L.C. Smith If you have any questions regarding the comments above, please do not hesitate to contact me. Very tr y yours, P1.L. Woodson Production Superintendent Alaska Operations MLW:bb ~"'~ ~"~ ,~`` r. ~ r~ ~~F ~; • 2 ~t7lt&~t~Jtt i~" ~5 Ch Chevron U.S.A. Inc. 575 Market Street, San Francisco, CA 941.05 Mail Address: P.O. Box 7643, San Francisco, CA 94120 f` ~ ~~,, ,3y`•r~ ~~F. J.J. Anders Manager, Alaska Division Land -Western Region December 15, 1980 PROPOSED CHANGES TO ALASKA ADMINISTRATIVE CODE TITLE 20, AAC 25.035 I~ir. Harry W. Kugler Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Kugler: Chevron U.S.A. Inc. presents the following comments on the amendment of Title 20, AAC 25.035 of the Regulations as provided for in the Alaska Statutes, Title 31, Chapter 05, Article 1, Section 30.05.030 (c) and (d). Title 20, AAC 25.035 (c) (1) (A) should be worded as follows: API 2M, 3M and 5M stacks have at least three preventers including one with pipe rams which fit the drill pipe or tubing being used, (The rams in this preventer will be changed to fit the casing when casing is being run.) one with blind rams and one annular type. Title 20, AAC 25.035 (c) (1) (B) should be worded as follows: API lOM and 15M stacks have at least four preventers including two with pipe rams which fit the drill pipe or tubing being used, (One set of these rams will be changed to fit the .casing when casing is being .run.) one with blind rams and one annular type. Title 20, AAC 25.035 (c) (6) should be worded as follows: Two emergency valves with rotary subs for all connections in use and the necessary wrenches must be conveniently located on the drilling floor; one valve must be inside (BOP of the) spring loaded type (a flapper type float valve and float sub are considered to fill this requirement); the second valve must be of the manually operated ball type, or equivalent valve. We do not have comments on the proposed changes to Title 20, ARC 25.035 (c) (2) and (c) (5). We will be happy. to answer any questions you may have on-our comments. ~., ... - ~ Uery r ly yours, :JDB:sj' , s '. . J. Anders d ~7~j`t~~ c~i ~ Jo l~ t~1 /.~ i //i~f L .h.>coG? ~A"i'r'' /C u~~P/' ~~JrYI , (/l 1 C QYC/ '/~ ~Is1 / D /~17 ~ /'~?!/7U19 (.~.a0lY1N? . ti ~ le ~/ ~ /G~ ~ / J~s,i °"~ ~®~ v~ _ ~ G.~, //~ s ;- ~.~cxo ~ - ~'/ /Pe :T !fie 1yJe4/7 ~ ~!'7~ a ~ YQN~s %~ / ~ ~Ol~ G~G~ ~`~ ~ E' ~',p e 7`u~irrq e ~ l~ssi~q b~is~ /~sec.~~ C/ Q ~ ~f~°N ~~c~Q~c~ ~e~~ey -~~~~ two l hch~ ,T7T lkP S>2e o/~ ~Yf~i~~jpi~e Ti~bir~q a'~ CmS~vgy ~Qli~~ ~uG/. C~J ~ ~ (~ U /~ ~, ~ 4 4 ~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~ ~ PUBLIC HEARING STATE OF ALASKA Alaska Oil and Gas Conservation Commission Conservation File No. 172 In the Matter of the Amendment of Title 20, AAC 25.035 of the Regulations as provided for in the Alaska Statues, Title 31, Chapter 05, Article 1, Section 31.05.030 (c). DATE: December 17, 1980 PLACE: 3500 Tudor Road,. Assembly Meeting Room Anchorage, Alaska TIME: 9:40 a.m. APPEARANCES: ' HOYLE H. HAMILTON, Chairman of the Alaska~0i1 and Gas Conservation Commission HARRY W. KUGLER, Commissioner with the Alaska Oil and Gas Conservation Commission LONNIE C. SMITH, Commissioner with the Alaska Oil and Gas~~l Conservation Commission MICHAEL ARRUDA, with the Attorney General's Office, Stated of Alaska ~', AUDIENCE PARTICIPANTS: ~I JOHN B. WILLIS, Drilling Engineering Supervisor for Exxonl! Company U.S.A. RICHARD H. REILEY, District Drilling Engineer for Sohio Alaska Petroleum Company in Anchorage * * * * * * * * .~", j.14Y ! ~, . F „1 r :~ , R & R COURT REPORTERS ~ ~ C;~~~, 810 N STREET. SUITE 101 509 W. 3R0 AVENUE 1007 W. 3RD AVENUE fif ~,., ~~' ~t)jJ 277-0572 - 277-0573 274-9322 272-7815 ~' ~~' ./ Il ud~~~jty~ ANCHORAGE. ALA SKA 99501 ~7 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 ~'~ 20 21 22 23 24 25 1 P R O C E E D I N G S - 2 - MR. HAMILTON: Good morning. There's such a larg group here, I suppose we ought to identify ourselves. I'm Hoyle Hamilton, Chairman of the Commission. To my left is Commissioner Harry Kugler. To my immediate right is Commissioner Lonnie Smith and to my far right is Mike Arruda with the Attorney General's office. This is a public hearing called by .the Alaska Oil and i Gas Conservation Commission to accept oral or written commences regarding the adoption of amended regulations as provided for in the Alaska Statutes, Title 31, Chapter 5, Article 1, Section 31.0 I i 030 (c) . The proposed amendments are to Title 20 of the Alaska Administrative Code 25.035 (c) entitled Blowout prevention equip-'~ ment. Notice of this hearing was published in the Anchorage Time: on November the 14th, 1980. A copy of the published notice will be made part of the hearing record. Draft copies of the proposed regulation amendments are available here at the table if anyone cares to have a copy. And the hearing record will be kept open for two weeks following today's hearing for any additional written comments. That will be until 4:30 p.m, December the 31st, 1980. So at this time we would like to open it up for any public R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7516 ANCHORAGE. ALASKA 99501 ~ ~; • i - 3 - 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 t comments. We have two gentlemen in the audience.. .Which one woul like to come fortiZ first? And for the record, if you would, identify yourself and your affiliation before you give your comme ts. NR. WILLIS: Okay. My name is John B. Willis, W-I-L-L-I-S. I'm drilling engineering supervisor for Exxon Compa y U.S.A. COURT REPORTER: Would you mind being seated, please? MR. WILLIS: Okay. COURT REPORTER: Thank you. MR. WILLIS: My technical qualifications are grad ate of Texas A. & M. University 1974 with a B.S. degree in chemical engineering. I've been employed by Exxon for six and a half year , including five years drilling experience for which I've been in Alaska, supervising Exxon's drilling engineering group here in Anchorage, responsible for all of the technical planning and surveillance for North Slope exploration drilling program.- Exxon supports the proposed revision as written. I'd like to make one comment. We interpret Section (c) part (1) (B) to require no more than two sets of pipe rams under any condition , specifically included for running casing. We interpret that to mean that one set of drill pipe and one set of casing ram. will be sufficient, and that for a tapered string one set pipe rams for the large size drill pipe and one set for the small size dril R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 277.0573 274-9322 272-7515 1 2 3 4 5 6 7 8 9 ~ ~ - 4 - pipe would be sufficient. As long as the Commission intended for the regulations to read -- have that meaning, then we fully suppo~ .them. Also following the hearing I'd like to submit our written request to the Commission on all of the supporting technical reasons for the change in the regulations to be entered as part of the hearing record. MR. HAMILTON: Yes, they will be. MR. WILLIS: Thank you.. MR. SMITH: Shall we ask questions now or what? MR. HAMILTON: Yes, if you want to. John, would you come back, please? 15 16 17 18 19 20 21 22 23 24 25 1 ~ MR. SMITH: If you don't mind, I have a question or two. With reference to your -- your interpretation of (c) (1) (B), you -- would you state that again? That --.that -- Do I understand that you interpret that to mean just no more than two set of pipe rams of the same size? Or two pipe rams in the stack MR. WILLIS: Two sets of pipe rams in the stack. The part I was referring to states, quote, "including two that fit the size of drill pipe or casing being used," unquote. That could possibly mean that we would have to have two sets of casing rams in the stack or two sets of pipe rams for each size of drill pipe being used, which would conflict the earlier requirement that we must have at least three pipe rams, three preventers -- R & R COURT REPORTERS 810 N STREET. SUITE 101. 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572- 277-0573 2.74-9322 272-7515 A NCHORAGE. ALASKA 99501 't i i 1 2 3 4 5 6 7 8 9 10 11 12- 13 14 15 16 ~' 17 18 19 20 21 22 23 24 25 1 - 5 - excuse me, four preventers, including three sets with -- with r in them. So I wanted to make sure that we understood what the Commission meant on that, and if there's a con -- conflict we'd like to pursue that and possibly ..... MR. SMITH: No, that was -- that was not the intent. MR. WILLIS• MR. SMITH: of casing may or may not be the sizes of tubular goods MR. WILLIS: MR. SMITH: Slope ..... Okay. It was as you stated. The wording appropriate here. It's because of Right. ..... or tubing run on the North MR. WILLIS: Yeah. MR. SMITH: ..... was specifically the way it got. in there. We've already had suggestions about changing that from -- to just drill pipe or tubing. MR. WILLIS: Uh-huh. MR. SMITH: Or -- let me ask this question with regard to that. Do you normally -- does your company change the ra -- one set of rams when you're running casing? Now, I mean, not casing for tubing, but casing? MR. WILLIS: Definitely. R & R COURT REPORTERS 810 N STREET. SUITE 101. 509 W. 3RD AVENUE 1007 W. 3R0 AVENUE 277-0572 - 277-0573 274-9322 272-7515 ANCHORAGE. ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 I 16 17 18 19 20 21 22 23 24 25 MR. SMITH: You do? • - 6 - MR. WILLIS: Yes. We require two sets of pipe rams while drilling, one below the drilling spool and one above the drilling spool. We have one set of blind rams .below the spoo For running casing we replace the. top set of pipe rams, which. are above the spool, with casing rams (Indiscernible) have the blind rams below the spool to obtain well control at all times. And if we were to have some kind of a problem while we were running casing, we would nibble up additional blow-out preventers on top of this stack to get back our normal (ph) safety. factor a couple preventer (phi. For tapered string we run one set of pipe, rams for the small drill pipe and one set for the large drill pipe. MR. SMITH: Do you think you would object if that was reworded to say that -- including two that fit either the size of drill pipe tubing or casing. being used? MR. WILLISc No, that sounds very good. MR. HAMILTON: Any more questions? MR. KUGLER: Just a minute. We have a -- a written comment on this already here and it's from Chevron U.S.A. and their wording is similar to what Commissioner Smith was sayin , that -- including two with pipe rams, which fit the drill pipe or tubing being used. Again we'd have to have the same understan - ing that you were talking about, that it means one for the drill pipe and one for the tubing, I guess. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7515 n N~HC~RAGE ALASKA 99501 • • - 7 - 11 2 3, 4 51', 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. SMITH: Okay. MR. KUGLER: Casing rams would always be changed to use the size casing, right? MR. WILLIS: Right. MR. SMITH: I have one more question. John, with regard to the previous submittal of data to support this hearing, did-you ask to have that entered into the record? ~. MR. WILLIS: Yes. MR. HAMILTON: Okay, it will be entered into the i record. Thank you, Mr. Willis. MR. WILLIS: Thank you. MR. HAMILTON: Mr. Reiley. MR. REILEY: Mr. Chairman and members of the Stat of Alaska Oil and Gas Conservation Commission, my name is Richard H. Reiley, R-E-I-L-E-Y. I'm the district drilling engineer for Sohio Alaska Petroleum Company in Anchorage. I graduated from the University of Alaska in 1969 with a Bachelor of Science degre in mining engineering. And in 1973 with a masters degree in engineering management. I have 1Q years of drilling and producti experience, including two years of drilling supervision for both exploration and developing wells in Alaska. I'm currently responsible for the engineering planning and technical assistance for Sohio's exploration and development drilling activities in Alaska. R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 2770573 274-9322 272-7515 l~N~'~~C`PAi. ~- Ai. i1 ":I!A SaP501 ~. 1 2 3 4 5 6 7 811 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 1 I • • _ g _ This testimony is in regards to Conservation File No. 172, the amendment of Title 20, AAC .25.035 of the .Regulations as provic for in the Alaska Statutes, Title 31, Chapter 05, Article 1, Sect= 21.05.030 (c) and (d). Sohio Alaska Petroleum Company supports the written testimo~~.y and conclusions of Exxon U.S.A. It supports the issuanc of the Conservation File No. 172 as written, with the exception of Section. (d) -- correction, Section (c), paragraph (B) should state, include, too, that fit either the size of the drill pipe -• pipe tubing or casing being used. Thank you. MR. HAMILTON: Thank you, Mr. Reiley. Questions? MR. SMITH: Not quite yet. Just a second. Let ~ me regroup here a little bit on the rev~.ew of this stuff a minute) Richard. MR. REILEY: We might also state that our company policy is to use a set of casing rams whenever we're running intermediate or long string, as is Exxon. MR. SMITH: Yes, Richard, have -- has your compan previously operated a well with a BOP stack as per specifically these new regulations would allow, with a 5,000 annular on a 10,000? MR. REILEY: Yes, sir. We are operating one now under an exception granted earlier this year on Challenge Island. The three ram stack, drilling spool and a 5,000 annular R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7515 A NCHORAGE. ALASKA 99501 ied _on ;e .. - 9 - 1 2 3 4 5~ 6i 7' 8 9 10 11 12 13 14 15 16 . 17 18 19 20 21 22 '~ 23 24 25 t ' with a 10,000 rams. MR. SMTTH: Yes. Let it be entered into the record that that was under Conservation Order 170, Challenge ~i, Island, one exploratory well. And I think it would be well that the data presented for that conservation order be entered into the record. I nave nothing further. MR. KUGLER: I have no questions. MR. HAMILTON: Thank you, Mr. Reiley. MR. REILEY: Thank you. MR. SMITH.: I would recall John and do the same thing with him on Conservation Order 171. If I could ask another question of you, John. Has your company, operated any wells in Alaska with this present configuration as proposed, the 5,000 annular on a ].0,000 stack? MR. WILLIS: Yes, sir, we have. We had that .configuration on our Point Thompson #4 well or Point Thompson #3 well,. and we also are currently rigging up a stack on our Alaska State C-1 well with that configuration. We have also received exception from the State for Point Thompson #6, Alaska State D-1 and E-1 wells under the new regulations. All of our previous wells ire under the old regulations. MR. SMITH: Okay, the new regulations are the current-state regulations ..... MR. WILLIS: Right. R & R COURT REPORTERS BIO N STgEE T, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 277.0573 274-3322 272-7BIB AN^HORAC:F ALASKA f~9501 r - 10 - 1 MR. SMITH: ..... amended (ph) in this year. 2 The -- and the Point Thompson 6, Alaska State D and Alaska State 3 E, I might point out for the record, were under -- granted under 4 Conservation Order 171. And I'd like for the submittal of 5 ~I evidence for that record to be entered into this record. 6 MR. HAMILTON: Fine. Thank you. 7 MR. SMITH: Thank you, John. 8 MR. HAMILTON: That seems to be all the people ~ 9 10 we have here today that want to comment on the proposed amendment 11 to the regulations. We'll close the hearing at this time, but 12 I would like to repeat again that'the hearing record will be kept 13 open until December the 31st, 1980, at the close of business at 14 ' 4:30 p.m. for additional comments. Thank you for attending.. 15 E N D O F P R O C E E D I N G S 16 17 18 19 2U 21 22 23 24 25 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7515 { nNC-.H C1RA(:F A1.4 AKA 99501 1 2 3 4 5 6 7 8 9 10 11 i 12 13 14 15 16 17 18 19 20 21 22 23 24 25I 11 C E R T I F I C A T E UNITED STATES OF AMERICA ) ss. STATE OF ALASKA ) I, Joyce Bigelow, Notary Public, in and for the State of Alaska, residing at Anchorage, Alaska, .and Electronic Reporter for R & R Court Reporters, do hereby certify: That the annexed and foregoing transcription of the Publi Hearing of the Alaska Oil and Gas Conservation Commission, re: Conservation File No. 172, was taken before me on the 17th day of December, 1980, beginning at the hour of 9:40 a.m., in the Assembly Meeting Room, 3500 Tudor Road, Anchorage, Alaska, pursuant to notice of such said Public Hearing. That this transcription of the Public Hearing of the Alaska Oil and Gas Conservation Commission, re: Conservation File No. 172, is a true and correct transcription of said Public Hearing, taken by me electronically and thereafter transcribed by me. I am not a relative or employee or attorney or counsel of any parties at said Public Hearing, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affix d my seal this 29th day of December, 1980. __~ i F' .~. / S E A L ~ Not'ary Pubri~-^~fi and for Alaska / ~ / :--' ~-'"~ My Commission expires 7/2:5/81 R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 274-9322 272-7615 ANCHORAGE. ALASKA 99501 ~3 NOTICE OF PUBLIC HEARING STATE OF ALASKA• Alaska Oil Gas Conservation Commission Conservation File No. 172 Re: The amendment of Title 20, AAC 25.035 of the Regulations as provided for in the Alaska Statutes, Title 31, Chapter 05, Article 1, Section 31.05.030 (c) and (d). Notice is hereby given that the Alaska Oil and Gas Conserva- tion Commission has found it necessary to amend Title 20, AAC 25.035 of the regulations. The regulation,. as currently written, requires imprudent use of certain annular preventers when BOP. stacks of 10M and 15M.ratings are necessary. The proposed amend- ment in which .Title 20 AAC 25.035 (c) (1) and (2) are substan- tially changed and Title 20 AAC 25.035 (c) (5) and (6) are amended is as follows: (c) Blowout Prevention Equipment: (1) before drilling below the surface casing, and until completed, a.well must have remotely controlled BOP's, and the working pressure of the BOP's and associated equipment must exceed the maximum surface pressure to which they may be sub- jected except that the annular preventer_need not have a working pressure rating greater than 5000 psig. The BOP stack arrange- ments shall be as follows: (A) API 2M, 3M, and 5M stacks have at least three preventers, including one equipped with pipe rams that fit the size of drill pipe or casing being used, one with blind rams, and one annular type; (B) API lOM and 15M stacks have at least four preventers, including two that fit the size of drill pipe or casing being used, one with. blind rams .and one annular type. (2) information submitted with Form 10-401 must in- clude the anticipated downhole pressures to be encountered, the maximum surface pressures to which the BOP.. equipment may- be subjected, the criteria used to determine. these pressures, and a well-control procedure which indicates how the preventers will be utilized for pressure control operations if the maximum surface pressures should .exceed the rated working pressure of the annular preventer. (5) the BOP equipment must include a drilling spool with [minimum two-inch] side outlets (if not on the blowout Conservation Filco. 172 preventer body), a minimum three-inch choke line and minimum two-inch choke manifold, a kill line, and a fillup line; the drilling string must contain full opening valves above and imme- diately below the kelly during all circulating operations using the kelly, with the necessary valve wrenches conveniently located on the rig floor; and (6) two emergency valves with rotary subs for all connections in use and the necessary wrenches. must be conven- iently located on the drilling floor; one valve must be an inside [BOP of the] spring-loaded type; the .second valve must be of the manually operated ball type, or equivalent valve. A public hearing will be held. in :the Municipality of Anchorage Assembly Room, 3500 East Tudor Road, Anchorage, Alaska at 9:30 AM on Wednesday December 17, 1980. Harry W. Kugler Commissioner Alaska Oil and Gas Conservation Commission -2- ADVERTISING ORDER ' u I ~'lnchorac-e Ti,-~Ics B E4 0 [ : etit T'ourtt ~ Avenue I Fr~craorage, Alr~s~l; 99501 S H E ~ ~~,~ -° ,:J ~~ 4 INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIEDAFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORMf WITH ATTACHED COPY OF ADVERTISE- MENT MUST BE SUBMITTED WITH INVOICE. VENDOR NO. 2. PUBLISHER DEPT: NO. A.O. NO. AD' Q8 4052 DATE OF A.O. I'?cv~r~~er 12, 1>is0 DATES ADVERTISEMENT REQUIRED: T;ave:~: s.,;er 1~? , 198a la].aal~a Oil & Gas Con: ervaticn Cc~:~rsssion F 3001 Forcu~~ine I:rive 0 1[nchorac~e, Alasla S?9501 M THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. BILLING ADDRESS: S AIiE AFFIDAVIT-OF-PUBLICATION UNITED STATES OF AMERICA aska 1 STATE OF Al ss third .DIVISION. BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED Edith Yan WHO, BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT HE/SHE IS THE Legal Clerk OF The Anchorage Times PUBLISHED AT Anchorage IN SAID DIVISION third AND STATE OF Alaska AND THAT THE ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WAS PUBLISHED IN SAID PUBLICATION ON THE 14th DAY OF November 1980,ANDTHEREAFTER FOR -0- CONSECUTIVE DAYS, THE LAST PUBLICATION APPEARING ON THE 14th DAY OF November 1980, AND THAT THE RATE. CHARGED THEREON IS NOT IN EXCESS OF THE RATE lx 9 1/2 inches $39.90 L79181 CHARGED PRIVATE INDIVIDUALS. ~~ F'.a ~ ~ r+f `~ 4 ,(~;' ~ d~,~ j ~ SUBSCRIBED Ai~ SWORN TO BEFORE ME ~ ~G~ ^ ~',~I~,~ THIS 17th DAY OF Novemk~er1980 "C `~~:; " >~;~Jr~i,, n ~ ~p ` Cal tn0 ~/ NOTARY PUBLIC FOR STATE OF Alaska s~~;~ MY COMMISSION EXPIRES i`'[ay 1st, 1982 ~ REMINDER- ATTACH INVOICES AND PROOF OF PUBLICATION- ----.-- l ~ STATE OF ALASKA ... ~ ~ i NOTICE OF PUBLIC HEARING STATE OF ALASKA . Aiasko Oil GasGonserVatton Commission Coneervation'File Na: 172 Re: The amendment of Title 20, AAC 25.035 of the Regulations os provided for in The Alaska Std• Lutes, Title 31, Chapter O5, Arti- cie 1, Section 31.05.030. (c) and (d). Notice Is hereby given that The Aloska.011 antl Gas Conserva- lion Commmisslon has found It necessary to amend Title 20, AAC 25.035 of the regulations. The regulation, as currently Written, requires imprudent use of certain annular preventers when BOP stocks of lOM and 15M ratings are necessary. The .proposed amendment In which Title 20 AAC 25.035 (cl (1) and 12) are substantiolly changed , and Title 20 AAC 25.035 (W (51 and (6) are amended Is as fol• lows: (c) Blowout Prevention Equipment: ... (1) before drilling below the surface casing. and until COmPlefed, O WBII mUSt have remotely controlled BOP's, and the working pressure of the BOP's and associated equipment must. exceed the maximum sur- `-~ face pressure to which.thev mov be sublected except " that the onnular preventer -. need not have a working pressure rating greater than 5000 psis. The BOP stack arrongements shall be as follows: (A) API ZM, 3M, and SM stacks have at least three preventers, including one equipped Wiih pipe rams that Ylt the size of drill pipe or casing being used, one with blind rrms, and One annVlOr type; (.B) API lOM a~ 15M stacks have at least four preventers, including two shot fit the size of drill pipe Or casing being used, - one with blind rams and one annulor type. (2 with Formtl0-401smusttln~- clude the. anticipoted down- . hole Dressures to be en- countered, the maximum surface Pressures to which the BOP equipment may be sublected, the criterlo used To determine these Ares- sures, and a well-control ~ Procedure which indicates how the preventers will be utilized for pressure control operations If the maximum surface Pressures should exceed the rated working _ pressure of the annular pre- -~ venter. I (5) the BOP e4uipment must Include a drilling spool with (minimum two-inch) side ~. " outlets (if not on the blow- "' out preventer body), o mimimum three-Inch ctwke 1 line and o minimum two- • Inch choke manifoltl, a kill line, and a filtup line; the '. drilling string must contain • full opening wolves above I and immediately below the ~' kelly tluring all circuloting - operations using the keliv, with the necessary valve wrenches conveniently , locoted on the rig floor, and (6 with ofafY subs for OII con- nections In use and the nec- essarv wrenches must be ~ conveniently located on the drilling floor, one volve must be an Inside (BOP of the) spring-loaded type: the ' second valve must be the of '. the manually operated ball type, or equivalent valve. • A public hearing will be held In the Municipality of Anchoroge Assembly Room, 3500 East' Tudor Road, Anchorage, Alaska at 9:30 AM on Wednesday De- cember 17, 1980. - /s/ Harry W. Kugter, Commissioner • AlOSka Oil and Gas Conservation Commission AO-08 4052 Pub: Nov. 14, 1980 - -A.Lo% ��Wz E?~ON COMPANY, U. S.A POUCH 6601 • ANCHORAGE, ALASKA 99502 EXPLORATION DEPARTMENT OFFSHOREIALASKA DIVISION ~~ ~'t October 24, 1980 l Request for Variance to Regulation 20AAC 25.035(C)(2) Mr. Hoyle H. Hamilton, Chairman State of Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Hamilton: , In letters dated August 29, 1980, Exxon filed applications for permits to drill the following Arctic Slope wells: 1) Point Thomson Unit No. 6 2) Alaska State "D" No. 1 3) Alaska State "E" No. 1 ~ CUMIv'~~r( -- ~ COA~1/JI ~~" -RES L=NG _~ ~ ENG _ _~_2 ENG-_ 3 EiJG _~ 4 ENG 1 GEOL_ 2 GEOL _ ~ 3 GEOL'_ _ ~ STAT TEC_ STAT TEC - I ---- - CONFER: FILF: As stated in the permit applications, Exxon plans to use a 13-5/8" inch 5000 psi working pressure annular BOP as part of the blowout preventer system whose other components are rated for 10,000 psi. Although-.this is in accord with widely accepted safe industry practice and with American Petroleum Institute guidlines, it is in technical violation of Miscel- laneous Boards, Commission regulation 20 AAC 25.035 at para- graph (C) (2) . Exxon requests a variance to this regulation to, allow use of the 5000 psi WP annular preventer on these four wells. A full discussion of the technical aspects of our position was recently submitted to you in the form of a letter requesting revision of the subject regulation. This letter is included as an attachment for your reference in considering this request. Very truly yours, ~, Robert K. Riddle ~ '~ I RAM:jrh 240-500-200 c r~ A DIVISION OF EXXON CORPORATION ,1 1., ~`~~~r .' ~~~~~f''r! COMPANY, U S.A. POUCH 6601 ANCHORAGE, ALASKA 99:,02 (907) 276 A652 ALASKA OPEIaAiIO NS WFSTEPN DIVISION W ~Ar Wii. TAr~~)P X11 `I t7 AilON ~ t!~~NA if N Gentlemen: State of Alaska Oil and Gas Conservation Commission 3001 .Porcupine Drive Anchorage., AK 99501 U K t=) M C~Opl~ September 23, 1980 Exxon 'requests revision of the recently enacted Ivliscel.laneous Boards, Commissions regulation 20 AAC 25.035 Blowout }'revention Equipment which at paragraph' (c) (2) requires, in part, "the working pressure of any BOP and associated equipment must exceed the. maximum surface pressure t,o which they may be subjected;..." On the surface,. this appears to be an entirely reasonable requirement and little or no comment was raised during Lhe review period prior to enactment. Careful consideration now reveals that the requirement is contrary to existing prudent drilling practice since "any BOP" includes the annular preventer whose working pressure might be required. to exceed 5,000 psi depending upon interpretation of the !undefined term "maximum surface pressure" and the unclear wording "to which they. may be subjected." Current safe BOP selection pra'etice for drilling higher pressure wells entails selection of ram-t.ype preventers. with a working pressure exceeding the apticipated surface pressure for any casing on which they are installed and selection of t:he annular preventer. to exceed the anticipated surface pressure which would be encountered in well control_oper.ations. The intended use of the annular preventer is to provide initial closure on any par. of a drill string at relatively low pressure, in the event of a well kick, to permit the operator to analyze the pr.obl.em. Tyre operator would then proceed with well control. operations r.rsing the ram-type preventers and/or the annular preventer depending on pressures and the condition of the..wel.:L, ttiJith current technology i.n equi.pment, abnormal pressure detection and well control training, the initial pressure wi~l.l normally not exceed 1.,000- to 2,000 psi, and if_ well control;'procedures result in pressures in excess of 2,000 to 2,500 psi,~prudent operating practice is to conduct the well control operation. using the ram-type preventers thus effectively isolating the annular preventer from the h-i.gher pressure. That is to say, the ,annular preventer would not be subjected t:o pressures exceeding 5,000 psi. A DIVISION OF EX %(~N CORPORATION State of A1~[s~cn • '. Septe-uber 23, 1.9~ Page 2 `I'her.e have been no documented operational instances where an annular preventer. having a working pressure greater than 5,000 psi would have prevented a blowout, yet literal interpretation of the subject regulal_ion could result i.n the requirement for such a preventer. By design and operational usage, an annular. preventer is int=ended to provide fora limited range of functions under low to moderate pressure, i.e., less than 5,000 psi. A regulatory requirement for a greater than 5,000 psi. wor.lcing pressure annular preventer. distorts the purpose and operational usage of the annular preventer, potentially jeopardizing well control and safety under high pressures. Moreover, it is projected that several years would be required to design, shop test, and opera- tionally validate the reliability of 1.0,000 psi. annular pre- venters of: the 1.6-3/4 inch'or',''18-5/8 inch sizes required -in some drilling programs. This regulation could limit the availab_i.lity of rigs for scheduled exploraGi.on drilling programs, r.equ:ire r.rse of prototype equipment during well control operations, and result in no tangible advancement in technology or increased safety. Attached f_or. your review .is .,a general. discussion of blowout preventer equipment and the use of preventers in well control. In view of the problems discussed above, Exxon requests that 20 AAC 25.035(c) (2) be revised as follows: r n~ ~s _ ~ ~' ~~ ~~~ ~ ~~~n~,~ "the caorking pressure of any r.am-type BOP and associated equipment must exceed the anticipated surface pressur-c of any casing string on which it is t.o he used and the working pressure of any annular~BOP must exceed the pressure to which it may be subjected'.in well control operations; infor- mation submitted with Form 10-401 must include anticipated for_mal_ion pressures to be ,encountered, the anLici.}gated surface pressure for each casing string, anti.cipat.ed pres- sures to which the annular.preventer may be subected in well control operations, anal the criteria used to determine these pressures consistent' w`th 20 AAC 25.030 Casing and Cementing; We believe the above requirement. more clearly states the estab- lished criteria f.or selection o,f BOI' equipment and will allow for the differing methods of program,desi_gn now used by indusLr.y. Although we realize: that .your decision roust be based on t:lce merits of the case, we would like to point out a recent precedent involvinga USGS OCS regulati•on.,. 'hhis was a BOP requirement ,,~,~,~, ~ essentially identical. to 20 'AAC 25.035 (c) (2) which was rev:i_sed `~t r+~"~ along the lines proposed. `..Your. consideration of this proposed "° revision is respectfully requested. Yours very truly, -/~ /)~ 1'~-~,1'~ , -_ ~ ~ ' ,' TLP/RAM/kb Attachment 28-Z • • • 1 1 1 W. Monte 'I'ayl.or .; GENERAL DESCRLPTION OF BLOWOUT' PREVENTER EQUIPI`lEN'I' AIJU USt1GE A blowout preventer (BOP) system consists of several engineering designed components that can be systematically operated in the event of unexpected flow from a well.. The BOP system is used initially to close a well in, and thereafter to hold back pressure on the wellbore, while circulating a mud weight of sufficient hydrostatic pressure under controlled conditions to overcome the influx. Figure 1 is a schematic of a 130P system, commonly referred to as a BOP stack. The basic components are similar: a wellhead connection to the previously se_t and cemented casing strings; pipe yarn preventers; blind ram; an annular preventer; and a system ~f li.nes and valves. to direct fluid intro or out of the BOP when various components of the system are functioned for well control operations. The number. and position of the pipe rams and blind ranr may vary with parti.cul.ar requirements of a given weld, the operator's weL1~ control procedures, and t:o some extent., on the complexity of the BOP system. The size, shape and c~onCr_ol. of the BOP system are specific~31'ly designed for a particu]ar rig. 1`la~or changes to_a BOP stack,,often involve changes in handling procedures and auxiliary rig .equipment. The pipe rams, blind ram, and annular preventers are designed and used prima r.i]y for closing and'sealing functions. '`'hey alsc? have features .that provide for redundancy and .secondary functions. Figure 2 is a schematic of the primary sealing method of t:he pipe rams, blind ram, and annular preventer. ~, Pipe rams are semicircular 'concave faced components having primary sealing surfaces designed 'to match the outside diameter of the particular pipe i.n use.' Blind rams are so id faced com- ponents, with elastic and metal sealing surfaces .for closure and sealing with nothing opposite the ram. Some blind rams are equipped with pipe shearing blades which can close, shear, and effect a seal. The rams 'a~-e opened and closed by positive con- trolled operating fluid applied to the ram piston. The annular preventer is equipped with a large ring of clastic sealing material (rubber or neoprene) designed to close on open hole or around any size ~r 'shape pipe. The primary closing method is positive operating pressure applied to a shaped piston resul.ti.ng in a "squeezing, out" effect of_ the elastic element. Depending on the design of 'part i.cul.ar annular preverrt.ers , well.- bore pressure from below may also ,~~ct on t:he piston t:o "pressure assist" the squeezing of the element. The primary opening con- trol. method is pos:i.tive ope.r,ating pressure applied to the shaped piston to reverse i.ts trave. at~c~ allow the e]_ement to relax to its normal configuration. The significance of the designed oper- ational features of the annular preventer is discussed below. ~~ i OPE:IZA1'IONS During normal dr.i.lling operations, control of the well. is main- twined by using adequate hydrostatic pressure f.rorn the mud column i.n the wellbore, monitoring of various drilling parameters, and through proper crew training. As stated. previously, the i.~l.owout preventer system allows for closing in a well when unexpected flow occurs. 'Ihe 130P unit is intended to provide the operator with a series of alternative operational. functions, by use of the individual components, to control the i_r~flux by circulating fluid in the wellbore. The control of the wellbore depends on properly designed equipment, prudent operation of the equipment, and proper training of personnel performing the task. Pipe rams arc: considered t_he pri.mar.y means of scaling around drill pipe and the blind rams for sealing on open hole. }lccog- nizing the adverse mechanical effect that could occur. iF. the pipe rams were closed on other than their designed pipe size or if t:he blind rams were closed on gther than open hole, the annular preventer ~~~as designed to allow initial closing around irregular sizes and shapes. It is, ther.ef_ore, generally Lhe first preventer. to be closed in an emergency.... Well control can then be trans- itioned in an orderly fashion' td ,the primary pipe rams for long term sealing and operational control.. Figure 3 is the closing-i.n pr,ocedure employed by Exxon. It: is similar to the procedure used'; by any prudent dr.illi.ng operator. Figure 4 represents calculations of various conditions of gas infux that. would have to !.occur prior to closing the annular preventer i_n order for it to'be subjected to initial pressure greater than 5,000 psi. With operators and crews trained for abnormal pressure .detection anti well control in accordance with cur. rent standards, the lilceli.hood of unexpected flow of the intensity and volume reflected by the example is extremely remote. For example, they pit volume increase a]ar.m normally would have a sensit.i.vity of 10 bbl. or less. Response time for a trained•dri ling crew t:o check the well for flow and properly close the, annular preventer is two mi.n. or less. Assuming; ail influx rate equivalent. to 20,000 .bbl. per clay, t:he total influx prior to shut in would be '38~bb1•, which is much less than the values shown i.n Figur.e /+. '.Accordingly, the annular preventer would not be subjected to•~i.n_itial. closed-in pressures greater than -5 , 000 psi . At: ter close-.i n.,_ i f _t_he _oherator rea:~onably__ an= ticipates_5urface pressures exceedin about 2,,500 psi the ~i_>e --- - -- - - 1- - ---- -- ~ --- - - - 1 ' -- - -l 1 - rams are r-out.incly_used for_hri_mary sealin~_and contrul.l_LInCt1.oT1_ -- ----- --- -- -- - ing_of either of the~ipe rams •or .blind rams will ~ solace the annular preventer_:from any _sub~equent high well pressures that mi ht occur d~_~rin __control_operations. 2. • . A secondary feat=ure designed Igor and operationally. engineered into the use of a blowout preventer system (the primary function is again to provide sealing) is the ability of moving pipe into or out of the wellbore under pressure. This procedure, called "stripping", is not a common occurrence during well control but is a desirable alternative t.o have available under Borne circumstances. Lt can be safely handled with existing components of the BOY system and trained crews. In Borne situations, strip- ping can be performed with t:he pipe rams or with the annular preventer or with a combination of the preventers. Due to it_s infrequent occur.r-ence, the stripping procedure is yenerall.y employed only after considerable .forethought and planning. Figure 5 shows a fundamental calculation Lo determine if strip- ping is a viable alternative.. If there. is an insufficient down- ward force (from the weight of the pipe already in the hole) to overcome the upward Lorce generated by the unexpected infa.ux, stripping cannot be performed and snubbing operations become the alternative. This i.s a less. frequent occurrence and specialty companies and equipment are necessary to .perform t:he procedure. If stripping is a viable and necessary option, a historical. preference, under low well.bor~ pressure, has been to str:ih with the annular preventer. TIZis', procedure is somewhat. less com- plicated, under low pressures, and reduces the possibility of damage to the primary sealing ram preventers that would he used for subsequent control operations once stripping has peen com- pleted. A generalized discussion of stripping with an annular preventer is presented in this paragraph. Recall that the annular pre- venter has a ring of elastic material, squeezed by a shaped piston upon application of pressure from the control accumulator and/or by wellbore pressure assist. The higher the well pressure, the tighter the, element is squeezed to maintain a pressure seal. As pipe is'moved through the annular pr. evenCer, friction from the pipe body and, the passage of the larger OD pipe tool. joints causes wear_ of the element. The higher the welll~or.e pressure and the required closing pressure, the greater_ the wear. The greater the wear, the greater .the closing pressure must be to maintain a seal. For the annular preventer designed with well pressure assisting hydraulic closing pressure,' th'e closing pressure can be reduced t.o minimi.ze frict:ion (and ..thus wear) between the element. and the pi.pc and tool joint. AC' relatively high wel.lbor.e pressures (2,000 to 2,500 psi), the hydraulic closing pressure can no longer 1~e r.educed sufficiently to, prevent excessive wear. clue to pipe movement: through the e]_ement. Depending on the size of the annu ar pr.eventer and pipe din use, o~enin~ pressure instead of closing pressure would have to he applied to the preventer to avoid excessive element fr:icti.on and wear. Applying opening pressure is considered to be an extremely hazardous procedure since a fluctuation in well pressure could allow the preventer to suddenly open. Even if the pipe rams were immediately closed, 3 • . uncontrolled f]ow could jeopardize rigand crew safety. lt•would bc~ a matter of chance at t.hi s time whether a tool joint were opposite the closing pipe ram thus darnag.ing it beyond subsequent sealing capabilit}~. For the annular preventer designed without wellbore assist, increasingly higher hydraulic closing pressures are required to mai.nt.ain t_he seal at higher and higher well pressures. Figure 6 sho~•;s results of shop tests of the wear. on an clement (st:r.ippi.ng cycles to fai.l.ure) relaCive to incr.easi.ng wellbore prc:ssurc and the resulting increase in cl~si.ng pressr.rre. -Note th<~ drast.ic reduction in element life when well. pressure is increased from ].,500 to 3,000 psi. While t:he results of. the tests may vary somewhat among prevent:ers, the size pipe used or the type of element installccl, it is Exaon's position t:hat. the test: i_s strongly indicative of the results that wil.1 be obtained at higher .well pressures. In other words, the stri.ppi_ng wear life of an annular preventer is greatly reduced at increased wellbore pressures. Of equ<r1 significance is Chc need for- the e.l emc~nt to maintain its sealing capability when repeatedly m<>ving t:he smaller diameter pipe body, then tt~e larger diameter tool. joi.nl and then the srnal.ler diarne.t.et;, pipe body again through the pre- venter. The element's ability to maintain a seal under this procedure is related to the amount of wear and pressure to which i t: i.s srrb_ject_ed. h though., a .. provision is avail ahl e for "sl.ight:ly" reducing the amount'of closing force on the element as the tool joint starts through, the opening and closing segri~~nces of an annular preventer are not totally positive. 'Clris is due t:o the larger sealing and piston areas involved, the amount of probable. wear, and the relati_v,ely large fluid operating volumes. For these reasons, i_t is Exxon's normal policy not to attempt stripping operations using art annular preventer, r_e~a_rdless of its_~ressure__rating, when well_~ressr.rre exceeds_ 2_,000 to ~.,SUU psi.. Our practice is supported by the experience oI O~~is Fng.ineeri.ng Corporation's worl.dwi.de stripping and snubbing oper- ations. Ot:is' views on the subject are reflected in their letter_ 01 February 1.1, 1980, Figure' 7: Supporting documentation c~.u~ also be found in ~1P1 Recommended Practices for Blowout. Prevention Equipment Syst:ems RP53 Page 14; Figure 8. Pr.eventer. system arrangement:s for 5,000,E_10,00U, and 15,000 psi. pressure raLinl;s may utilize annular prevent:exs'rat.ed for 5,000 psi. Tn sr.rmmary, by design and operational usage, an <~rnnular preventer is intenclc•d to provide for a• .liuri.ted range of functions under low to moder~rt e press ire, i .e. , Less th.rn 5,000 psi.. !1 regulat<~ry requirement (or a greater than 5,000 hsi_ worlcing_ pressure annular preventer distnrt.s the purpose and operational usage oC the annular preventer, p.otent::ii l ly jeopardizing well control :rnd safety under high pressures. '~ T•torc~over, it is projected t:hat several years would be rc~c~uired to design, shop t.est, and oper- atic>na]ly vali_datc the reli:rhi.l.it_~ of 1.0,000 psi annular E~rc- vent crs of l he l f~-3//~ inch or- 18-5/8 inch- sizes requ:i.r.ed in some drilling programs. Phis regulation could limit the avai ability /, • of rigs Ior scheclul.ed exploration drilling programs, reduire use of prototype ec{u~pment during w~e11 control operations, and result in no tangible advancement in technology or increased safety. TLP/RAI`i/rms 211-A ,I ,I. ,~ ~` ., I l i y •'• 1 '~ .) TYPICAL L~ OWOUT PREVEN FR STACK FIGURE I BELL PIPE RAM ~ BLIND RAM ANNULAR PERATING 'ISTON 'IPE RAM >EALING .~ :CEMENT OPENING FLUID CLOSING FLUID OPERATING PISTON OPENING FLUI D BLIND RAM ~~ -SEALING "= CLOSING ~1 ELEMENT FLUID OPENING FLUID CLOSING FLUID FIGURE 2 ELASTIC SEALING.,. ELEMENT OPENING CHAMBER PISTON CLOSING CHAh1Ec^ PREVENTER BODY • • LAND, PLJ~TFORM b JACK~JP OPEMTIOhI FUII BOP STACK ON CQMPETENT CJ1SlMG CLOSING-IN PROCEDURE rF ANY OF THE FOLLOWING OCCUR: 1. HOLE NOT TAKING CORRECT AMOUKT Of MUD ON TRIP. 1 GAIN IN PIT VOLUME. INCREASE FLON ACROSS SHAtE-SHAKER. 4 DfliLIING BREAK. 5 INCREASE OR DECREASE IN PUMP PRESSURE. S. GAS CUT MUD OR CHLORIDE INCREASE. 1. /ICK UP KELIV FEET UNTIL TOOL JOINT CLEARS ROTARY TABLE (P+.o* ioKr-ovt d~oub' /uv* Gwr+ irrd+ ro ,. niun rMr ~ roo~-YO~nr n nor rn eOrl Z SHUT DOWN MUD Pl1MP5. 7 CHECK WELL FOR GLOW. SHUT WELL IN AS FOLLOWS NOTiFV SUPERINTENDENT AND TOOL -USHER iMMEDi~TELV! IS WELL FLOWING YES OrEId CHOh;. ~i I~ ~ YALE r; OId BOP CONTAOLPANEI CLOSE ANNULAR BOP CLOSE CHOKES RECORD SHUT-IN DP AND CSG -RESSURES, AND PIT LEVEL GAIN _ l CONTROL'WELI AS DIRECTED '~ NO -- RESUh1E OPERATIONS AS DIRECTED I FIGURE 3 i ~ . REQUIRED INFLUX FOR INITIAL WELL SHUT-IN PRESSURE TO EQUAL 5,000 PSI Well Drilling Barrels With A of Gas Influx TD-Ft Mud Wt-ppq 2 ppg Kick With A 4 ppq Kick 13,000 10.0 ~ 389 242 15,000 12.0 293 156 17,000 14.0 227 98 ~; 1 WELLBORE CONFIGURATION 5 inch drill pipe 9-5/8 inch casing 540 ft., 6-1/2 inch drill collars B-1/2 inch hole ,. Figure 4 •' LENGTI-I~pF PIPE REQUIRED~O STRIP THROUGH ATfNULAR Vs WELLB E PRESSURE 16 0 0 0 i Z Q J Z t~. w Z W W 0 s h O Z 4.! v 14 12 10 g 6 4 2 0 660 FT., 6 %2`~OD D C I N I I pp q MW ,; ;~ • ~~ 5 k 70FT.,8~~ OG DC IN . ~ . . ~ FORCE WEIGHT UP =(PIPE OD) 2(WELL BO ,DOWN=(LENGTH OF PIPE • -FRICTION RE PRESSUR )(WEIGHT)(B E U IOpp~ MW L(0.765) OYANCE) 0 2 4 6 B 10 WELL PRESSURE --IOOOpsi FIGURE 5 STRIPPING TEST RESULTS 18 3/~4 ~~ AiVD ~ 6 3/4°~- 5000 P51 R~INULAR 1504 3000 PSI -~ WELL PRESSURE==1500 PSI ~• 800 PSI ._ r._. -. _.. - ~- -- `I CLOSIP~G 1000 __C~AMB.~R ;-- . - P~~SSURE PSI 500 N,4TURAt. OR NITRILE ELEMENTS 6 3/8~~ TOOL JOINT ON 5~~ GRILL PIPE 0~ 0 50® 1000 STRfPP1NG CYCLES 1500 FIGURE 6 + . • ~. o. wox ~•~eo o~-L~~s, Tcx.s ~bz» ,-AC. coot :i••:~:•waaw Tir. H. J. Flatt Exxon Headquarters Drilling Manager Exxon Company, .U.S.A. P. 0. Box 2180 Room 3005 Houston, TX 77001 Dear Sir: ~~V~ ~ February 11, 1980 With reference to your inquiry regarding t1~e u annular preventers, Otis has had no experience using any annular type preventer above 10 3/4 some experiences dok+n through.the years with e of drill pipe, sizes 3 1/2 through u 1 /2, usin annular preventer under 3,000 psi, but in each had adequate pipe in the hole.or~our'conventio meet available for stripping purposes. se of large bore strippin5 pipe I.D. We have had mergency stripping g the 7 1/16 I.D. case we either nal snubbing eouip- We regularly strip 1.315 O.D. through 2 7/B" O.D. using a pre- sized, molded stripper element similar to Hydril's RS Stripper, Composite Catalog, Page 3b74.' Most routine offshore workover is conducted with 1.315 O.D. pipe stripped through a molded stripper element sized to fit 4 1/16 bore"equipment, 3000 osi maximum, backup configuration. I would suggest that smaller pipe diameters in relation to large bore annular preventers could present a problem unless the elastomerlc material is adequately backed up by metal. One other concern is the tendency for the elastomeric materials to flow easily when the pressure differential approaches or exceeds the modulus of elasticity. This means that without near perfect metal backup, higher pressure sealing is not practical. We experience a certain amount of difficulty in the ram type preventer as well, and must be constantly aware of and accommodating to the metal We have used dual element stripping techniques but employ this method to lengthen element life as opposed to increasing working pressure ranges. Stripping•with~either the molded or annular type presents mayor problems when considering the change in areas as the point upset moves through the seal area from two standpoints: 1) Sufficient pipe weight must be present. to pull the point through the seal area, and 2) Strict attention must be placed on the type of point used. No square shoulders must be present and a very shallow angle must be used forthe diameter transition. Otis Engineering Gorporetion gHALL18URTONComaany PHILLI~ S SIZCR, P E. sa..c. vat ~.c.,ea.+ ~ac...c•~ D.•cc+e^ Figure 7. .~ ,~ •, ' •~ Mr. H. J. Flatt • • ' Fage Two February 11, 1980 One point I should mention is, the industry also uses the eeBpP's. stripping to indicate the movemWetaoe papkingraboutrannular type I have assumed in your inquiry equipment as opposed to ram type equipment. Our principal experience has been with ram type equipment, using .pipe sizes up through 7" O.D. and pressure up through 18,000 psi. l~he large pipe has been stripped with ram type BOP's against 2,000 psi and the smallest pipe has been associated with ram type. BOP's and 18,000 psi. We would, if required to rig up on an existing stack, test all BOP's including the annular to rated working pressulel~uI D°lladnular not attempt to strip more than 5,,000 psi using a 7- ~ preventer. We believe increases in bore will reduce this maximum drastically as 18 3/4 I.D. is reached. I hope the foregoing is useful. irk,helping you arrive at a decision but if additional information `is necessary, please contact me. Yours very truly, ,. OTIS ENGINEERING CORPORATION L Phillip S Sizer j PSS:mc ' cc: Mr. Homer Davis ~` ~ ., i ~, i .J. V J C ., AFZH~I:V(;N:41F:tiT CyF~r{F2~1'('L ARR~1ti(;h;11E:tiT C'r{K~itr1'('HA• AftFt:lti(,h:tith;tiT Triple kam Type Yreventers, Ht. OptionHl. CHf{~~}{r~:~'Ci, 'Annular pre~mter, A, mey have SM working preeeare rehng. T~'PICAL I3LOWOliT PRE~'E:~'I'F.I2 :~RR:;tiGE11I~ti'i'S F:QIt 5..1, 1011, ANll 1511 RATr,I) WORR1tiG PRESSURE SERVICE -SUBSEA II~iST~>LL~~TIOti F'iG. '?.I).7 ArZRA V(;E;41E•:NT 4:171 1~ `~ ETON COMPANY, U.S.A. POUCH 6601 • ANCHORAGE, ALASKA 99502 (907) 276-4552 ALASKA OPERATIONS WESTERN DIVISION W MONTE TAYLOR OPERATIONS MANAGER C .• a~ September 23, 1980 RES ENG 1_ENG~ 2 ENG_ 3 -ENG 4 ENG 1 G€OL 2 GE 3 GEO STRT TEC STAT T'EC FIL~s State of Alaska Oil and Gas Conservation Commission 3001 ..Porcupine Drive Anchorage, AK 99501 Gentlemen• Exxon requests revision of the recently enacted Miscellaneous Boards, Commissions regulation 20 AAC 25.035 Blowout Prevention Equipment which at paragraph (c) (2) requires, in part:, "the. working pressure of any BQP and associated equipment must exceed the. maximum ..surface pressure to which they may be subjected;.,," On the surface., this appears to be an entirely :reasonable requirement and little or no comment was raised during the review. period prior to enactment. Careful :consideration now reveals that the requirement is contrary to existing prudent drilling practice .since ".any BOP" includes the annular preventer whose working pressure might be required to exceed 5,000 psi depending upon interpretation of the undefined term "maximum surface pressure" and the unclear wording "to which they may be subjected." Current safe BOP selection practice for drilling higher pressure wells entails selection of ram-type preventers with a working pressure exceeding the anticipated surface Ares-sure for any casing on which they are installed and selection of the annnular preventer to exceed the anticipated surface pressure which would be encountered in well control operations. The intended use of the annular preventer is to provide initial closure on .any part of a drill string at relatively low pressure, in the event of a well kick, to permit the operator to analyze the problem. The operator would then proceed with well control operations using the ram-type preventers andJor the annular preventer depending on pressures 'and the condition of the well. With current technology in equipment, abnormal pressure detection. and well control. training, the initial pressure will normally not exceed 1,000 to 2,000 psi., and if well control procedures result in pressures in excess of 2,000 to 2,500. psi, .prudent operating practice is to conduct the well control operation using the ram--type preventers thus effectively isolating the annular preventer from the higher pressure. That is to say, the annular prevent~,r~.4rdc3wl~ t-n~a;,t be subjected to pressures exceeding 5 , 000 psi . ~ ~. ° ~ ., : ,_.:.~ A DIVISION OF EXXON CORPORATION :~~ ,, `, State of Alaska September 23, 1980 Page 2 There have been no documented operational .instances. where an annular preventer having a working pressure. greater than .5,000 psi would have prevented a blowout, yet literal interpretation of the subject regulation could result in the requirement for such a preventer. By design and operational usage, an annular preventer is intended to provide for a limited range of functions under low to moderate pressure, i.e., less than 5,000 psi. A regulatory requirement for a greater than 5,000 psi workng_pressure annular preventer. distorts the purpose and operational usage of the annular preventer, potentially jeopardizing well. control and safety under high pressures. Moreover, it is projected that several years would be required to design, shop test, and opera- tionally validate the reliability of 10,000 .psi annular pre- , venters of the 16-3/4 inch or 18-5/$ inch sizes required in some drilling programs.. This regulation could limit the availability of rigs for scheduled exploration drilling programs, require use of prototype equipment during well control operations, and .result in no tangible advancement in technology or increased safety. Attached for your review is a general discussion of blowout preventer equipment and the use of preventers in well control. In view of the problems discussed above, Exxon requests that 20 AAC 25.035(c) (2) berevised as follows: "the working pressure of any ram-type BOP and associated equipment must exceed the anticipated surface pressure of any casing string on which it is to be used and the working pressure of any annular BOP must exceed the pressure to which it may be subjected in well control operations; nfor- mation submitted with Form 10-401 must include anticipated formation pressures to be encountered, the anticipated surface pressure for each casing string, anticipated pres- sures to which the annular preventer may be subected in well control operations, and the criteria used to determine these pressures consistent with 20 AAC 25.030 Casing and Cementing; We believe the above requirement more clearly states the estab- lished criteria for selection of BOP equipment and will allow for the differing methods of program design now used by industry. Although we realize that your decision must be based on the merits of the case, we would like to point out a recent precedent involving a USES OCS regulation. This was a BOP requirement essentially identical to 20 AAC 25.035 (c) (2) which was revised along the lines proposed. Your consideration of this proposed revision is respectfully requested. Yours very truly, ~~%~ ` ~_ .~~~~ W. Monte Taylor TLP/RAM/kb Attachment 28-Z cc: R. K. Riddle GENERAL DESCRIPTION OF BLOWOUT PREVENTER EQUIPMENT AND USAGE A blowout preventer (BOP). system consists of several engineering 'designed components that can be sy tematcally operated in the event of unexpected flow from a well. The BOP system is used initially to close a well in, and thereafter to hold back pressure on the wellbore, while circulating a mud weight of sufficient hydrostatic pressure under controlled conditions to overcome the influx. Figure 1 is a schematic of a BOP system, commonly :referred to as a BOP stack. The basic components are .similar: a wellhead connection to the previously set .and cemented casing strings; pipe ram preventers; blind ram; an annular preventer; and a system of lines .and valves to direct fluid into or out of the BOP ..when various components of the. system are functioned for well control operations. The number and position of the pipe rams and blind ram may vary with particular requirements of a given well, the operator's well control procedures, .and to some extent, on the complexity of the BOP system. The size, shape and control of :the BOP system are specifically designed for a particular rig. Major changes to a BOP stack often involve changes in handling .procedures and auxiliary rig equipment.. The pipe rams, blind ram, and annular preventers are designed and used primarily for closing and sealing functions. They also have features that provide for redundancy and secondary functions. Figure 2 is a schematic of the primary sealing method of the .pipe ..rams, blind ram, and annular preventer. Pipe rams are semicircular concave .faced components having primary sealing surfaces designed to match the outside diameter of the particular `pipe in use. Blind rams are solid faced com- ponents, with elastic and metal sealing surfaces .for closure .and sealing with nothing apposite the ram. Some blind rams are equipped with pipe shearing blades which can close, shear, and effect a seal. The rams are opened and 'closed by positive con- trolled operating fluid .applied to the ram piston. The annular preventer is equipped with a large ring of elastic sealing material (rubber or neoprene) designed to close on open hole. or around any size or shape pipe. The primary .closing method is positive operating pressure applied to a shaped piston resulting in a "squeezing ..out" effect of the elastic element. Depending on the design of particular. annular preventers, well- bore pressure from below may also act on the piston to "pressure assist" the squeezing of the element. The primary opening .con- trol method is positive operating pressure applied to the shaped piston to reverse its travel and allow the element to relax to its normal configuration.-The significance of the designed oper- ational features of the annular preventer is discussed below. OPERATIONS During normal drilling operations, control of the well is main- tained by using. adequate hydrostatic pressure from the mud column in the wellbore, monitoring of various drilling parameters, and through proper crew training. As stated previously, the blowout preventer system allows for closing in a well when unexpected flow occurs. The BOP unit is :intended to provide the operator with a series of alternative operational functions, by use of the individual components, to control the influx by circulating fluid in the wellbore. The control of the wellbore depends on properly designed equipment, prudent operation of the equipment, and proper training of personnel performing the task. Pipe rams are considered the primary means of sealing around drill pipe and .the blind rams for sealing on open hole.. Recog- nizing the adverse mechanical effect that could occur if the pipe rams were closed on other than their designed pipe size or if the .blind rams were. closed on other than open hole, the annular preventer was designed to allow initial closing around irregular sizes and shapes. It is, therefore, generally the first preventer to be closed in an emergency. Well control can then be trans- itioned in an orderly fashion to the primary pipe rams for long term sealing and operational control. Figure 3 is the closing-in procedure employed by Exxon. It is similar to the procedure used by any prudent drilling operator. Figure 4 represents calculations of various conditions of gas infux that would have to .occur prior to closing the annular preventer in order for it to be subjected to initial pressure. greater than 5,000 psi. With operators and crews trained for abnormal pressure detection and well control in accordance with .current standards, the likelihood of unexpected .flow. of the .intensity .and volume reflected by the example is .extremely .remote. ~'or example, the pit volume increase alarm normally would have a sensitivi y of l0 bbl or less. Response time for a trained drilling crew to check the well for flow and properly close the annular preventer is two min. or less. .Assuming an influx rate equivalent to 20,000 bbl per day, the total influx prior to shut in would be 38 bbl, which is much less .than the values shown in Figure 4. Accordingly, the annular preventer would not be subjected to initial closed-in pressures greater than 5,000 psi. After close-in, if the operator reasonably an- ticipates surface pressures exceeding about 2, 00 psi, the pipe. rams are routinely used for primary sealing and control.Function- ing of either of the pipe rams or blind rams will isolate the annular preventer from any subsequent high well pressures that might occur during control operations. 2 A ,secondary feature designed for and operationally engineered into the use of a blowout. preventer system (the prmary'function is again to provide. sealing) is the ability of moving pipe into or out of the wellbore under pressure. This procedure, called "stripping.", is not a common occurrence during well control but is a desirable alternative to have available under some circumstances. It can be safely handled with existing components of the BOP system and trained crews. In some situations, strip- png can be performed with the pipe rams or with the annular preventer or with a combination of the preventers. Due to its infrequent occurrence, the stripping procedure is generally employed only after considerable forethought and planning. .Figure 5 shows a fundamental calculation to determine if strip- ping is a viable alternative.. If there is an insufficient down- ward .force {from the weight of the pipe already in the hole) to overcome the upward force ..generated by the unexpected influx, stripping cannot be performed and snubbing operations become the alternative. This is a less frequent occurrence and specialty companies and equipment are necessary to perform the .procedure. If stripping. is a viable and necessary option, a historical preference, under low wellbore pressure, has been to strip with the annular preven er. This procedure is somewhat less com- e plicated, -under low pressures, and reduces the passibility of damage to the primary sealing ram preventers that would be used fora subsequent control operations once s ripping has been com- pleted. A generalized discussion of stripping with an annular preventer is presented in this paragraph. Recall that the annular pre- venter .has a ring of elastic material,. squeezed by a shaped piston upon application of pressure from the control accumulator and/or by wellbore pressure assist... The higher the well pressure, the tighter the element is squeezed to maintain a p-ressure seal. As pipe is moved through .thee annular preventer, friction from the pipe body and the passage of the larger OD pipe tool. joints causes wear of the element. The higher the wellbore pressure and the required closing pressure, the greater the wear. The greater the wear, the greater the closing pressure .must be to maintain a seal. For the :annular. preventer designed with well pressure assisting hydraulic closing pressure, .the closing pressure can be reduced to minimize friction (and thus wear) between the element and the pipe and tool joint, At relatively high. wellbore pressures (2,40fl to 2,5flfl psi), the. hydraulic closing pressure can no longer be reduced sufficiently to prevent excessive wear .due to pipe movement through the element. pepending on the size of the annular preventer and pipe in use, opening pressure instead of closing pressure would have to be applied to the preventer to avoid excessive element friction and wear... Applying opening pressure is considered to be an extremely hazardous procedure since a fluctuation in well pressure could allow the preventer to suddenly open. Even if the pipe rams were immediately closed, 3 i ! uncontrolled flow could jeopardize rig. and crew safety. It would be a matter of chance at this time whether a tool joint were opposite the closing pipe ram thus damaging it beyond subsequent sealing capability. For the annular preventer designed without wellbore assist, increasingly higher hydraulic closing pressures are required to maintain the seal at higher and higher well pressures. Figure b shows results of shop tests of the wear on an element (stripping cycles to failure) relative to increasing wellbore pressure and the resulting increase in closing .pressure. Note `the .drastic reduction in element life when well pressure `is increased from 1,500 to 3,000 psi. While the results of the .tests may vary somewhat among. preventers, the size pipe used or the type of element installed, it is Exxon's. position that the test is strongly indicative of the results that will be obtained at higher well pressures. In other words, the stripping wear life of an annular preventer is greatly reduced at increased wellbore pressures. Of equal significance is the need for the element to maintain its sealing capability when repeatedly moving the smaller diameter pipe body, then the larger diameter tool joint and then the smaller diameter pipe body again through the pre- venter. The element's ability to maintain a seal under this procedure is related to the amount of wear and pressure to which it is subjected. Although a provision is .available .for "slightly" reducing the amount of closing force on the element as the_tool joint starts through, .the opening and closing sequences of an annular preventer are not. totally positive.. This is due to the larger sealing and piston areas involved, the amount of probable wear, and the relatively large fluid operating volumes. For these reasons, it is Exxon's normal policy not to attempt stripping operations using an annular .preventer, regardless of its ressure satin when well ressure exceeds 2,.000.t s Our practice is supported by the experience o Otis Engineering Corporation's worldwide stripping and snubbing oper- ations, .Otis' views on the subject are reflected in their letter of February ll, 19$0, Figure. 7. Supporting documentation can .also be found in API Recommended Practices for Blowout Prevention Equipment Systems RP53 Page 14, Figure 8. Preventer system .arrangements for 5,000, 10,000, and 15,000 psi pressure ratings .may utilize annular preventers rated for 5,000 psi.. In summary, by design and operational usage, an annular preventer is intended to provide for a limited range of functions under low to moderate .pressure, i.e., less than 5,000 psi. A regulatory .requirement for a greater than 5,00.0 psi .working pressure annular preventer distorts the purpose and operationa usage of the annular preventer, potentially jeopardizing well control .and safety under high pressures. Moreover, it is projected that several years would be required to design, shop test, and oper- atonally validate the reliability. of 10,000 psi annular pre- venters of the 16-3/4 inch or 18-5/8 inch sizes required in some drilling programs. This regulation could .limit the availability 4 • • of rigs for scheduled exploration drilling programs, require use of prototype equipment .during well control operations, and result in no tangible advancement in technology or increased safety. TLP/RAM/rms 211-A 5 • TYPICAL. BLOWOUT PREVENTER STACK BELL FIGURE I PIPE RAM BLIND RAM ANNULAR. 'FRAYING OPERATING ELASTIC SEALING STON PISTON ~ ELEMENT PE RAM :ACING _EMENT PENING QUID LOSING LUI D BLIND RAM SEALING. ELEMENT OPENING FLU I D CLOSING FLUID OPENING FLUIDy CLOSING FLUID FIGURE 2 • OPENING ;,HAMBER PISTON CLOSING CHAMBER _NTER t ~' i ~ ~ • LAND, PLATFORM 81 JACK~JP OPERATION FULL BOP STACK ON COMPETENT CAi1NG CLOSING-IN PROCEDURE 1F ANY OF THE FOLLOWING OCCUR: 1. HOLE NOT TAKING CORRECT AMOUNT OF MUD ON TRIP. 2. GAIN IN PIT VOLUME. 3. INCREASE FLOW ACROSS SHALE-SHAKER. 4. DRILLING BREAK. S. INCREASE OR DECREASE IN PUMP PRESSURE. 6. GAS CUT MUD OR CHLORIDE INCREASE. 1, -tCK UP KELLY FEET UNTIL TOOL ,JpINT CLEARS ROTARY TABLE. (R~or tp~u~vt dwuAd /uw Dwr+ n~ to iniurr rNr ~ roo~yoinr ii not in IQrI 2. SHUT DOWN MUD PUMPS. l CHECK WELL FOR FLOW. IS WELL FLOWING NO SHUT WELL IN AS FOLLOWS: WOTIFY SUPERINTENDENT ANp TOOL PUSHER IMMEDIATELY! 0 EN CHOP LII~~ VALVE ON BOP CONTROL PANEL CLOSE ANNULAR BOP CLOSE CHOKES RECORD SHUT-tN Df AND CSG. -RESSURES, AND PIT LEVEL GAIN COPITROL WELL AS DIRECTED RESUME OPERATIONS AS DIRECTED FIGURE 3 ._ • ~ REQUIRED INFLUX FOR INITIAL WELL SHUT-IN PRESSURE TO EQUAL 5,000 PSI Well TD-Ft 13,000 15,000 17,000 Barrels of Gas Influx Drilling With A With A Mud Wt-ppg 2 ppg Kick 4 ppg Kick 10.0 389 242 12.0 293 156 14.0 227 98 WELLBORE CONFIGURATION 5 inch drill pipe 9-5/8 inch. casing 540 ft., 6-1/2 inch drill collars 8-1/2 inch hole Figure: 4 LENGTH OF PIPE REQUIRED TO STRIP THROUGH ANNULAR Vs WELLBORE PRESSURE 16 0 0 0 Q z 0 W 0 z W W 0 s h O Z W v 14 12 10 8 6 4 2 0 0 660 FT., 6 %2"OD D C I N I I PP 9 MW 5 70FT.,8" OD DC IN FORCE WEIGH UP =(PIPE O0)2(WELL BO T DOWN=(LENGTH OF PIPE -FRICTION RE PRESSURE )(WEIGHT)(Bl IOppq MW (0.765) ~OYANCE) 2 4 6 8 10 -WELL PRESSURE -IOOOpsi FIGURE 5 STRIPPING TEST RESULTS 18 3/4~~ 150 AND 16 3/4~~- 5000 PSI ANNULAR 3000 PSI = WELL PRESSURE--1500 PSI 800 PSI CLOSING 1000 CHAMBER PRESSURE PS1 500 ~- • ~ ~ NATURAL OR NITRILE ELEMENTS 6 3/8~~ TOOL JOINT ON 5~~ DRILL PIPE ~ ~ 0 0 500 1000 1500 ' STRIPPING CYCLES FIGURE 6 ~~'~~ ~ P-+iu~P S Saca, P. E. sc«~o• v,cc -.c~~oc«~ Ttc««~u~ O~~cc•e. Mr. H. J. Flatt Exxon Headquarters Drilling Manager Exxon Company, U.S.A. P. 0. Box 2180 Room 3005 Houston, TX 77001 Dear Sir: -. o. eox a.aeo o~~~~s, TExAS 7~2~4 AP1 E~- COOC t~~-lnt-166.• February 11, 1.980 1~'ith reference to your inouiry regarding the use of large bore annular preventers, Otis has had no experience-stripping pipe using any annular type preventer above 10 3/4 I.D. We have had some experiences down through the years with emergency stripping of drill pipe, sizes 3 1/2 through 4 1/2, using the ? 1/16 I.D. annular preventer under 3,000 psi, but in each case we either had agequate pipe in the hole or our conventional snubbing equip- ment available for stripping purposes. We regularly strip 1.315 O.D. through 2 7/8" O.D. using a pre- sized, molded stripper element similar to Hydril's RS Stripper, Composite Catalog, Page 3674. Most routine offshore workover is conducted with 1.315 O.D. pipe stripped through a molded stripper element sized to fit 4 1/16 bore equipment, 3.,000 psi maximum, We have used dual element stripping techniques but employ this method to lengthen element .life as opposed to increasing working pressure ranges. Stripping with either the molded or annular type presents mayor problems when considering the change in areas as the point upset moves through the seal area from two standpoints: 1) Sufficient pipe weight must be present to pull the point through the seal area,. and 2) Strict attention must be placed on the type of point used. No square shoulders. must be present and a very shallow angle must be used for the diameter transition. I would suggest that smaller pipe diameters in relation to large bore annular preventers could present a problem unless the elastomeric material is adequately backed up by metal. One other concern is the tendency for the elastomeric materials to flow easily when the pressure differential approaches or exceeds the modulus of elasticity. This means that without near perfect metal backup, higher pressure sealing is not practical. We experience a certain amount of difficulty in the ram type preventer as well, and must be constantly aware of and accommodating to the metal backup configuration. Otis Engineering Gorporetion A i{ALUaURTON Comp~np Figure 7 ~, M Mr. H. J. Page Two February Flatt 11, 1980 ~ • One point I should mention is, the industry also uses the eeBOP's. stripping to indicate the movement of pipe through ram typ I have assumed in your inquiry we are talking about annular type equipment as opposed to ram type equipment'. Our principal experience has been with ram type equipment, using pipe sizes up through 7" O.D. and pressure up through 18,000 psi. The large pipe has been stripped with ram type BOP's against 2,000 psi and the smallest pipe has been associated with ram type BOP's and 18,000-psi. We would, if required to rig up on an existing stack, test all BOP's including the annular to rated working. pressure but would not attempt to strip more than 5,000 psi using a 7-1/.16 .I .D. annular. preventer. We believe increases in bore will reduce this maximum drastic-ally as 18 3/4 I.D. is reached. I hope the foregoing is useful in helping you arrive at a decision but if additional information is necessary, please contact me. Yours very truly, OTIS ENGINEERING CORPORATION ~7 L Phillip S Sizer ~PSS:mc cc: Mr. Homer Davis -~ ,~ ,~ a. ' t ~1 ~. to c m FIG. `L.D.4 ARRANGF.MF;NT CyRdRA"CL Triple Ram Type Preventers, Rt., Optional. ARRANGEMENT CHRdRA"CHA" ARRANGEMENT ~= H Rd Rd A"~=L a 3 A -, o~ m 0 ro A 0 3 ~~ A 'Annular preventer, A, may have 5M working preeeure rating. TYPICAL BLOWOUT PREVENTER ARRANGEMENTS FOR 5M, lOM, AND 15M RATED WORKING PRESSURE ' SERVICE -SUBSEA INSTALLATION FIG.2.D.? ARRANGEMENT CH RdltdA".A"LL FIG. 'L.I).5 FIG. 2.D.6