Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Oil and Gas Production Safety Systems, 54417-54432 [C1-2013-19861]

Download as PDF Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules Dated: August 14, 2013. Sandra Henriquez, Assistant Secretary for Public and Indian Housing. DEPARTMENT OF THE INTERIOR Bureau of Safety and Environmental Enforcement [FR Doc. 2013–21610 Filed 9–3–13; 8:45 am] 30 CFR Part 250 BILLING CODE 4210–67–P 54417 through 52284 in the issue of Thursday, August 22, 2013, make the following corrections: 1. On pages 52241 through 52242, the table should read as follows: [Docket ID: BSEE–2012–0005; 13XE1700DX EX1SF0000.DAQ000 EEEE500000] RIN 1014–AA10 Oil and Gas and Sulphur Operations on the Outer Continental Shelf—Oil and Gas Production Safety Systems Correction In proposed rule document 2013– 19861, appearing on pages 52240 Current regulation Proposed rule § 250.800 General requirements ............................................................ § 250.800 General. 250.801 Subsurface safety devices ....................................................... § 250.810 Dry tree subsurface safety devices—general. § 250.811 trees. Specifications for subsurface safety valves (SSSVs)—dry § 250.812 Surface-controlled SSSVs—dry trees. § 250.813 Subsurface-controlled SSSVs. § 250.814 Design, installation, and operation of SSSVs—dry trees. § 250.815 Subsurface safety devices in shut-in wells—dry trees. § 250.816 Subsurface safety devices in injection wells—dry trees. § 250.817 Temporary removal of subsurface safety devices for routine operations. § 250.818 § 250.821 Additional safety equipment—subsea trees. § 250.837 Emergency action and safety system shutdown. § 250.819 Specification for surface safety valves (SSVs). § 250.820 tkelley on DSK3SPTVN1PROD with PROPOSALS Subsurface safety devices in injection wells—subsea trees. § 250.832 Use of SSVs. § 250.833 Specification for underwater safety valves (USVs). § 250.834 Use of USVs. § 250.840 Design, installation, and maintenance—general. § 250.841 Fmt 4702 Subsurface safety devices in shut-in wells—subsea trees. § 250.830 Frm 00017 Design, installation, and operation of SSSVs—subsea § 250.829 PO 00000 Surface-controlled SSSVs—subsea trees. § 250.828 trees. Jkt 229001 Specifications for SSSVs—subsea trees. § 250.827 18:08 Sep 03, 2013 Subsea tree subsurface safety devices—general. § 250.826 VerDate Mar<15>2010 Emergency action. § 250.825 § 250.802 Design, installation, and operation of surface productionsafety systems. Additional safety equipment—dry trees. Platforms. Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 54418 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules Current regulation Proposed rule § 250.842 § 250.803 Additional production system requirements .......................... Approval of safety systems design and installation features. § 250.850 Production system requirements—general. § 250.851 Pressure vessels (including heat exchangers) and fired vessels. § 250.852 Flowlines/Headers. § 250.853 Safety sensors. § 250.855 Emergency shutdown (ESD) system. § 250.856 Engines. § 250.857 Glycol dehydration units. § 250.858 Gas compressors. § 250.859 Firefighting systems. § 250.862 Fire and gas-detection systems. § 250.863 Electrical equipment. § 250.864 Erosion. § 250.869 General platform operations. § 250.871 Welding and burning practices and procedures. § 250.880 Production safety system testing. § 250.890 Records. Safety device training ............................................................ § 250.891 Safety device training. § 250.806 Safety and pollution prevention equipment quality assurance requirements. § 250.801 cation. Safety and pollution prevention equipment (SPPE) certifi- § 250.802 Requirements for SPPE. § 250.804 § 250.805 Production safety-system testing and records ...................... § 250.807 Additional requirements for subsurface safety valves and related equipment installed in high pressure high temperature (HPHT) environments. § 250.804 Additional requirements for subsurface safety valves (SSSVs) and related equipment installed in high pressure high temperature (HPHT) environments. § 250.808 § 250.805 Hydrogen sulfide. § 250.803 What SPPE failure reporting procedures must I follow? § 250.831 Alteration or disconnection of subsea pipeline or umbilical. Hydrogen sulfide ................................................................... New Sections § 250.835 Specification for all boarding shut down valves (BSDV) associated with subsea systems. § 250.836 Use of BSDVs. § 250.838 What are the maximum allowable valve closure times and hydraulic bleeding requirements for an electro-hydraulic control system? § 250.839 What are the maximum allowable valve closure times and hydraulic bleeding requirements for a direct-hydraulic control system? tkelley on DSK3SPTVN1PROD with PROPOSALS § 250.854 Floating production units equipped with turrets and turret mounted systems. § 250.860 § 250.861 Jkt 229001 PO 00000 Frm 00018 Fmt 4702 Surface pumps. § 250.866 18:08 Sep 03, 2013 Foam firefighting system. § 250.865 VerDate Mar<15>2010 Chemical firefighting system. Personal safety equipment. Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules Current regulation 54419 Proposed rule § 250.867 Temporary quarters and temporary equipment. § 250.868 Non-metallic piping. § 250.870 Time delays on pressure safety low (PSL) sensors. § 250.872 Atmospheric vessels. § 250.873 Subsea gas lift requirements. § 250.874 Subsea water injection systems. § 250.875 Subsea pump systems. § 250.876 Fired and Exhaust Heated Components. 2. On page 52251, the table should read as follows: VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00019 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 EP04SE13.001</GPH> tkelley on DSK3SPTVN1PROD with PROPOSALS 3. On page 52254, Table 2 should read as follows: 54420 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00020 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 EP04SE13.002</GPH> tkelley on DSK3SPTVN1PROD with PROPOSALS 4. On pages 52256 through 52260, the table should read as follows: 54421 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules I Citation 30 CFR 250, Subpart A I 1 Reporting and Recordkeeping Requirement NEW: Demonstrate to us that by using BAST the benefits are insufficient to justifY the cost. Hou' ~ AvmgeNo. d of Annual ur en Responses B I Citation I 30 CFR250 Subpart H and NTL(s) 800(a) I ! 800(a); 880(a); 801(c) 802(c)(1 ); 852(e)(4); 861(b); 802(c)(5) 803(a) I I 803(b) I ! I 803(c) tkelley on DSK3SPTVN1PROD with PROPOSALS I 804 804(b); 829(b), (c); 841(b); VerDate Mar<15>2010 18:08 Sep 03, 2013 Reporting and Recordkeeping Requirement Hour Burden 2 justifications 10 2 responses 5 Subtotal I Annual Burden Hours 10 hours Average No. of Annual Responses Annual Burden Hours Non-Hour Cost Burdens* General Requirements Requirements for your production safety Burden included with system application. specific requirements below. Prior to production, request approval of pre1 76 requests production inspection; notifY BSEE 72 hours before commencement so we may witness preproduction test and conduct ins}Jection. 2 1 request Request evaluation and approval [OORP] of other quality assurance programs covering manufacture of SPPE. NEW: Submit statement/certification for: Not considered IC under 5 exposure functionality; pipe is suitable and CFR 1320.3(h)(1). manufacturer has complied with IVA; suitable fire fighting foam per original manufacturer specifications. NEW: Document all manufacturing, 2 30 I traceability, quality control, and inspection documents requirements. Retain required documentation until 1 year after the date of decommissioning the e~me!1t. 2 10 reports NEW: Within 30 days of discovery and identification ofSPPE failure, provide a written report of equipment failure to manufacturer. NEW: Document and determine the results 10 5 of the SPPE failure within 60-days and documents corrective action taken. NEW: Submit [OORP] modified 2 I submittal procedures you made if notified by manufacturer of design changes or you changed operating or repair procedures as result of a failure, within 30 days. Submit detailed info regarding installing Burdens are covered under 30 CFR 250, Subparts D SSVs in an HPHT environment with your APD, APM, DWOP etc. and B, 1014-0018 and 1014-0024. NEW: District Manager will approve on a Not considered IC per 5 case-by-case basis. CFR 1320.3(h)(6). I 0 76 2 0 60 20 50 I I 2 0 0 i I ! Jkt 229001 PO 00000 Frm 00021 Fmt 4702 Sfmt 4725 E:\FR\FM\04SEP1.SGM 04SEP1 EP04SE13.003</GPH> I 54422 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules Subtotal 128 responses Surface and Subsurface Safety Systems - Dry Trees Submit request for a determination that a 5% 41 wells well is incapable of natural flow'~____=______--+____ '--____ 1 VerifY the no-flow condition of the well y,. annually. Specific alternate approval requests requiring Burden covered under 30 approval. CFR 250, subpart A, 10140022. I 210 hours i i I 810; 816; 825(a); 830; 814(a); 821; 828(a); I I 838( c)(3); I 859(b); 870(b); rsI7(b); i 869(a); I i 246 o 1 IdentifY well with sign on wellhead that subsurface safety device is removed; flag safety devices that are out of service; a visual indicator must be used to identify the bypassed safety device. Record removal of subsurface safety device. I 817(b) 817(c) 1 I Subsea and Subsurface Safety NEW: NotifY BSEE: (1) if you cannot test all valves and sensors; (2) 48 hours in advance if monitoring ability affected; (3) designating USV2 or another qualified valve; (4) resuming production; (5) 12 hours of detecting loss of communication; immediately if you cannot meet value closure conditions. NEW: Request remote location approval. 825(b); 831; 833; 837(c)(5); 838( c); 874(g)(2); 874(f); i 1 827 831 I - I 837(a) L_______ : 837(b) I 1 I I i ! i o Burden included in § 250.890 of this subpart. Burden covered under 30 CFR 250, subpart D, 10140018. Subtotall 41 responses Subsea Trees o o 246 hours 7 (4) Y2 (5) Y2 1 I I request 1 1 submittal 2 NEW: Submit a repair/replacement plan to 2 monitor andtest. _____-+-________+-_____+-________---I 10 requests NEW: Request approval to not shut-in a Y2 5 subseawell~anem~genc~____~----~--~---~~-~~~~-~--~ NEW: Prepare and submit for approval a 2 1 submittal 2 plan to shut-in wells affected by a dropped ollject. -2 approvals 1 Y2 I NEW: Obtain approval to resume pr~ducti~!1~ P/!-_ PSgL_s_e_n s0-c-r_._ _ _ _ _j - -_ _ _-+____ __ 2 2 4 I NEW: VerifY closure time of US V upon request of District Manager. verifications 1 jl _________________ 837(c)(2) I I Request alternate approval of master valve [required to be submitted with an APM]. Usual/customary safety procedure for removing or identifYing out-of-service safety devices. 838(a); 839(a)(2); I 838(c)~EW: .,- / I I Request approval to produce after i~ss of communication; include alternate 2 1 approval 2 valve closure table. I VerDate Mar<15>2010 18:08 Sep 03, 2013 $5,030 per submission x 1 = $5,030 $13,238 per offshore visit x 1 = $13,238 $6,884 per shipyard visit x 1 = $6,884 13 10 130 applications required/supporting information, for a production safety system with> 125 components. 25 - 125 components. Jkt 229001 PO 00000 Frm 00022 Fmt 4702 Sfmt 4725 E:\FR\FM\04SEP1.SGM 04SEP1 EP04SE13.004</GPH> tkelley on DSK3SPTVN1PROD with PROPOSALS Subtotal 28 responses 24 hours Production Safety Systems i---84-2-;----r-jS-U-b-m-it-a-p-p--li-ca-t-io-n-,-and all r---1-6----rI-I-ap-p-h-' c-at-io-n---rl-------1-6----- 54423 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules i I $1,218 per submission x 10= $12,180 $8,313 per offshore visit x 1 = $8,313 $4,766 per, shipyard visit x 1 = $4,766 8 20 160 applications I I I [2500:,"G I Submit modification to application for pmduction safety system whh > 125 cOl11P.c>nents. 25 125 components. r I I I I I I $6~4=r~~X2~L! I modifications .. .. .1 ~~"~ l"" SUbmiSSi;~J-18T~,¥o,,~1 modifications I ·1 $201 ~ission x 758.1 $152,35~ 842(b) 842(c) 842(d), (e); 842(1) 5 NEW: Your application must also include certification(s) that the designs for mechanical and electrical systems were reviewed, approved, and stamped by registered professional engineer. [NOTE: Upon promulgation, these certification production safety systems requirements will I be consolidated into the application hour burden for the specific cO!!l£.().nents:J NEW: Submit a certification letter that the mechanical and electrical systems were installed in accordance with approved designs. NEW: Submit a certification letter within 60-days after production that the as-built diagrams, piping, and instrumentation diagrams are on file, certified correct, and stamped by a registered professional engineer; submit all the as-built diagrams. ] NEW: Maintain records pertaining to approved design and installation features and as-built pipe and instrumentation diagrams at your offshore field office or location available to the District Manager; make available to BSEE upon request and retained for the life of the facility. 329 1,645 modifications $85 per submission x 329 = $27,965 192 6 32 certifications 6 tkelley on DSK3SPTVN1PROD with PROPOSALS I 851(b); 852(a)(3); 858( c); 865(b); 851(c)(2) VerDate Mar<15>2010 18:08 Sep 03, 2013 I I 32 letters 16 ;,s ;,s 9,485 I hours ·-1I _JesI~ons~s_._ -----_._---$343,794 non-hour cost burdens I PO 00000 Frm 00023 Fmt 4702 Sfmt 4725 I 1,426 Add' , system R eqmrements Itlona I P ro d uctlOn S NEW: Request approval to use uncoded 1 request 2 pressure and fired vessels beyond their 18 months of continued use. I 615 records 23 Maintain [most current] pressure-recorder I information at location available to the District Manager for as long as information is valid. NEW: Request approval from District 1 10 requests Manager for activation limits set less than 5 I Jkt 229001 I I 208 32 records I 192 32 letters I I 6 Subtotal 851(a)(4) I E:\FR\FM\04SEP1.SGM 04SEP1 2 14,145 10 I I EP04SE13.005</GPH> < 25 components. 54424 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules i ! psi. 10 requests 1 i 852(c)(l) I NEW: Request approval from District 10 ~ _______+_ Manager to vent to some other location. -+---------------1---------1--------1 i 852(c)(2) I NEW: Request a different sized PSV. 1 1 request 5 ,----------------1------------------------------·-----------------------------.-----1----------------+-----------------------+--------------------1 ! 852(c)(2) i NEW: Request dIfferent upstream locatIOn 1 5 request 5 ! I of the PSV. 852( e) Submit required design documentation for Burden is covered by the o unbonded flexible pipe. application requirement in r-----c-------+---~--c---~---:------c-~------c--------~--§~2--5-10-5·-8-42~T-------:c-:----~------~~--1 855(b) Maintain ESD schematic listing control 615 listings 9,225 function of all safety devices at location conveniently available to the District !--_ _ _ _+-M_anager for the life of_t_h_ec-f:ac_i_lity-,,-,._ _ _ _!--_ _ __ _ _ + - - - - - _ + - - - - - - I __ i 858(b) NEW: Request approval from District 1 1 request 1 I Manager to use different procedure for gas, i well gas affected. 859(a)(2) Request approval for alternate firefighting Burden covered under 30 o CFR 250, subpart A, system. 1014-0022. --+------------------------------------------------------------------------------------1--"-------------- '-.-------+---------------------1 859(a)(3), Post diagram of fire fighting system; furnish 5 38 postings 190 i (4) evidence firefighting system suitable for Ii II ~----------------------- -=-=-::-:::-:--_ _ II-I I 859(b) I I 860(a); related NTL(s) 860(b) I 860(b) , 861(b) I : 864 ~ ______ , 867(a) +-:'o~p<e-=ra:o:t,=-io-cl1~i~ su!>geezi~!illl=a::c:t-=es=-:·_;:__--_+_:=____:_--J---:-__:-------+-------1 NEW: Request extension from District Burden covered under 30 0 Manager up to 7 days of your approved CFR 250, subpart A, 1014departure to use chemicals. 0022. ---~~-~~c-~--~~~---+--c~-_,~~---___+--~---+ Request approval, including but not limited 22 31 requests 682 to, submittal of justification and risk assessment, to use chemical only fire prevention and control system in lieu of a water system. NEW: Minor change(s) made after approval 'is 10 minor 5 rec'd re 860(a) - document change; maintain changes the revised version at facility or closest field office for BSEE review/inspection; maintain for life offaciiity. I NEW: Major change(s) made after approval 2 2 1 major I rec'd re 860(a) - submit new request change w/updated risk assessment to District Manager for approval; maintain at facility or closest field office for BSEE review/inspection; maintain for life of facility. NEW: Submit foam concentrate samples 2 500 1,000 annually to manufacturer for testing. submittals 12 615 records 7,380 Maintain erosion control program records for ~;ce~yq~Uea~ers~st.~;:mc-a-k-e- a- va-i-la-b- I-_e__tco~~B--S--E~E~U~-p-o~-n----4---~--+_~-----+_-~--~ NEW: Request approval from District 6 1 request 6 ~---c_ _ _!--M_a~er to install te~rary qua_rt_er_s_._ _---+_ _ _ ____+--------+------+ I 867(b) NEW: Submit supporting 1 I request 1 information/documentation if required by I I District Manager to install a temporary ~i_ _ _ _ _+-fi_lr_e_w_a_t_e_~s_t_e_m_._ _ _~_ _ _ _ _ __+----~-----_+-_ _ _ _ ~ 867(c) NEW: Request approval fonn District 300 requests 300 manager to use temporary equipment for VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00024 Fmt 4702 Sfmt 4725 E:\FR\FM\04SEP1.SGM 04SEP1 EP04SE13.006</GPH> tkelley on DSK3SPTVN1PROD with PROPOSALS 1-1 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54425 BILLING CODE 1505–01–C You must submit: Details and/or additional requirements: (1) A schematic piping and instrumentation diagram ............................... Showing the following: (i) Well shut-in tubing pressure; (ii) Piping specification breaks, piping sizes; (iii) Pressure relief valve set points; (iv) Size, capacity, and design working pressures of separators, flare scrubbers, heat exchangers, treaters, storage tanks, compressors and metering devices; VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00025 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 EP04SE13.007</GPH> tkelley on DSK3SPTVN1PROD with PROPOSALS 5. On page 52271, the table should read as follows: 54426 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules You must submit: Details and/or additional requirements: (v) Size, capacity, design working pressures, and maximum discharge pressure of hydrocarbon-handling pumps; (vi) size, capacity, and design working pressures of hydrocarbon-handling vessels, and chemical injection systems handling a material having a flash point below 100 degrees Fahrenheit for a Class I flammable liquid as described in API RP 500 and 505 (both incorporated by reference as specified in § 250.198). (vii) Size and maximum allowable working pressures as determined in accordance with API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems (incorporated by reference as specified in § 250.198). (2) A safety analysis flow diagram (API RP 14C, Appendix E) and the related Safety Analysis Function Evaluation (SAFE) chart (API RP 14C, subsection 4.3.3) (incorporated by reference as specified in § 250.198). if processing components are used, other than those for which Safety Analysis Checklists are included in API RP 14C, you must use the same analysis technique and documentation to determine the effects and requirements of these components upon the safety system. (3) Electrical system information, including .............................................. (i) A plan for each platform deck and outlining all classified areas. You must classify areas according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2; or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2 (both incorporated by reference as specified in § 250.198). (ii) Identification of all areas where potential ignition sources, including non-electrical ignition sources, are to be installed showing: (A) All major production equipment, wells, and other significant hydrocarbon sources, and a description of the type of decking, ceiling, and walls (e.g., grating or solid) and firewalls and; (B) the location of generators, control rooms, panel boards, major cabling/conduit routes, and identification of the primary wiring method (e.g., type cable, conduit, wire) and; (iii) one-line electrical drawings of all electrical systems including the safety shutdown system. You must also include a functional legend. (4) Schematics of the fire and gas-detection systems ............................. showing a functional block diagram of the detection system, including the electrical power supply and also including the type, location, and number of detection sensors; the type and kind of alarms, including emergency equipment to be activated; the method used for detection; and the method and frequency of calibration. (5) The service fee listed in § 250.125. .................................................... The fee you must pay will be determined by the number of components involved in the review and approval process. 6. On page 52272, the table should read as follows: Applicable codes and requirements (1) Pressure and fired vessels where the operating pressure is or will be 15 pounds per square inch gauge (psig) or greater. (i) Must be designed, fabricated, and code stamped according to applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler and Pressure Vessel Code. (ii) Must be repaired, maintained, and inspected in accordance with API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment (incorporated by reference as specified in § 250.198). (2) Pressure and fired vessels (such as flare and vent scrubbers) where the operating pressure is or will be at least 5 psig and less than 15 psig. tkelley on DSK3SPTVN1PROD with PROPOSALS Item name Must employ a safety analysis checklist in the design of each component. These vessels do not need to be ASME Code stamped as pressure vessels. (3) Pressure and fired vessels where the operating pressure is or will be less than 5 psig. Are not subject to the requirements of paragraphs (a)(1) and (a)(2). (4) Existing uncoded Pressure and fired vessels (i) in use on the effective date of the final rule; (ii) with an operating pressure of 5 psig or greater; and (iii) that are not code stamped in accordance with the ANSI/ASME Boiler and Pressure Vessel Code. Must be justified and approval obtained from the District Manager for their continued use beyond 18 months from the effective date of the final rule. VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00026 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54427 Item name Applicable codes and requirements (5) Pressure relief valves .......................................................................... (i) Must be designed and installed according to applicable provisions of sections I, IV, and VIII of the ASME Boiler and Pressure Vessel Code. (ii) Must conform to the valve sizing and pressure-relieving requirements specified in these documents, but (except for completely redundant relief valves), must be set no higher than the maximum-allowable working pressure of the vessel. (iii) And vents must be positioned in such a way as to prevent fluid from striking personnel or ignition sources. Must be equipped with a level safety low (LSL) sensor which will shut off the fuel supply when the water level drops below the minimum safe level. (6) Steam generators operating at less than 15 psig ............................... (7) Steam generators operating at 15 psig or greater .............................. (i) Must be equipped with a level safety low (LSL) sensor which will shut off the fuel supply when the water level drops below the minimum safe level. (ii) You must also install a water-feeding device that will automatically control the water level except when closed loop systems are used for steam generation. 7. On pages 52275 through 52276, the table should read as follows: For the use of a chemical firefighting system on major and minor manned platforms, you must provide the following in your risk assessment . . . Including . . . (A) The type and quantity of hydrocarbons (i.e., natural gas, oil) that are produced, handled, stored, or processed at the facility. (B) The capacity of any tanks on the facility that you use to store either liquid hydrocarbons or other flammable liquids. (C) The total volume of flammable liquids (other than produced hydrocarbons) stored on the facility in containers other than bulk storage tanks. Include flammable liquids stored in paint lockers, storerooms, and drums. (D) If the facility is manned, provide the maximum number of personnel on board and the anticipated length of their stay. (E) If the facility is unmanned, provide the number of days per week the facility will be visited, the average length of time spent on the facility per day, the mode of transportation, and whether or not transportation will be available at the facility while personnel are on board. (F) A diagram that depicts: quarters location, production equipment location, fire prevention and control equipment location, lifesaving appliances and equipment location, and evacuation plan escape routes from quarters and all manned working spaces to primary evacuation equipment. (ii) Hazard assessment (facility specific) .................................................. (A) Identification of all likely fire initiation scenarios (including those resulting from maintenance and repair activities). For each scenario, discuss its potential severity and identify the ignition and fuel sources. (B) Estimates of the fire/radiant heat exposure that personnel could be subjected to. Show how you have considered designated muster areas and evacuation routes near fuel sources and have verified proper flare boom sizing for radiant heat exposure. (iii) Human factors assessment (not facility specific) ............................... tkelley on DSK3SPTVN1PROD with PROPOSALS (i) Platform description .............................................................................. (A) Descriptions of the fire-related training your employees and contractors have received. Include details on the length of training, whether the training was hands-on or classroom, the training frequency, and the topics covered during the training. (B) Descriptions of the training your employees and contractors have received in fire prevention, control of ignition sources, and control of fuel sources when the facility is occupied. (C) Descriptions of the instructions and procedures you have given to your employees and contractors on the actions they should take if a fire occurs. Include those instructions and procedures specific to evacuation. State how you convey this information to your employees and contractor on the platform. VerDate Mar<15>2010 18:25 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00027 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 54428 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules For the use of a chemical firefighting system on major and minor manned platforms, you must provide the following in your risk assessment . . . Including . . . (iv) Evacuation assessment (facility specific) ........................................... (A) A general discussion of your evacuation plan. Identify your muster areas (if applicable), both the primary and secondary evacuation routes, and the means of evacuation for both. (B) Description of the type, quantity, and location of lifesaving appliances available on the facility. Show how you have ensured that lifesaving appliances are located in the near vicinity of the escape routes. (C) Description of the types and availability of support vessels, whether the support vessels are equipped with a fire monitor, and the time needed for support vessels to arrive at the facility. (D) Estimates of the worst case time needed for personnel to evacuate the facility should a fire occur. (v) Alternative protection assessment ...................................................... (A) Discussion of the reasons you are proposing to use an alternative fire prevention and control system. (B) Lists of the specific standards used to design the system, locate the equipment, and operate the equipment/system. (C) Description of the proposed alternative fire prevention and control system/equipment. Provide details on the type, size, number, and location of the prevention and control equipment. (D) Description of the testing, inspection, and maintenance program you will use to maintain the fire prevention and control equipment in an operable condition. Provide specifics regarding the type of inspection, the personnel who conduct the inspections, the inspection procedures, and documentation and recordkeeping. (vi) Conclusion .......................................................................................... A summary of your technical evaluation showing that the alternative system provides an equivalent level of personnel protection for the specific hazards located on the facility. 8. On pages 52279 through 52280, the table spanning those two pages should read as follows: Then you must install a . . . If your subsea gas lift system introduces the lift gas to the . . . tkelley on DSK3SPTVN1PROD with PROPOSALS (1) Subsea Pipelines, Pipeline Risers, or Manifolds via an External Gas Lift Pipeline. VerDate Mar<15>2010 API Spec 6A and API Spec 6AV1 (both incorporated by reference as specified in § 250.198) gas-lift shutdown valve (GLSDV), and . . . FSV on the gas-lift supply pipeline . . . PSHL on the gas-lift supply . . . meet all of the requirements for the BSDV described in 250.835 and 250.836 on the gas-lift supply pipeline. upstream (in board) of the GLSDV pipeline upstream (in board) of the GLSDV 18:25 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00028 Fmt 4702 Sfmt 4702 API Spec 6A and API Spec 6AV1 manual isolation valve . . . downstream (out board) of the PSHL and above the waterline. This valve does not have to be actuated. Additional requirements (i) Ensure that the MAOP of a subsea gas lift supply pipeline is equal to the MAOP of the production pipeline. an actuated fail-safe close gas-lift isolation valve (GLIV) located at the point of intersection between the gas lift supply pipeline and the production pipeline, pipeline riser, or manifold. (ii) Install an actuated fail-safe close gas-lift isolation valve (GLIV) located at the point of intersection between the gas lift supply pipeline and the production pipeline, pipeline riser, or manifold. Install the GLIV downstream of the underwater safety valve(s) (USV) and/or AIV(s). E:\FR\FM\04SEP1.SGM 04SEP1 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54429 Then you must install a . . . If your subsea gas lift system introduces the lift gas to the . . . (2) Subsea Well(s) through the Casing String via an External Gas Lift Pipeline. (3) Pipeline Risers via a Gas-Lift Line Contained within the Pipeline Riser API Spec 6A and API Spec 6AV1 (both incorporated by reference as specified in § 250.198) gas-lift shutdown valve (GLSDV), and . . . Locate the GLSDV within 10 feet of the first of access to the gas-lift riser or topsides umbilical termination assembly (TUTA) (i.e., within 10 feet of the edge of the platform if the GLSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the GLSDV is in the vertical run of a riser, or within 10 feet of the TUTA if using an umbilical). locate the GLSDV within 10 feet of the first of access to the gas-lift riser or TUTA (i.e., within 10 feet of the edge of the platform if the GLSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the GLSDV is in the vertical run of a riser, or within 10 feet of the TUTA if using an umbilical). API Spec 6A and API Spec 6AV1 manual isolation valve . . . FSV on the gas-lift supply pipeline . . . PSHL on the gas-lift supply . . . on the platform upstream (in board) of the GLSDV pipeline on the platform downstream (out board) of the GLSDV. downstream (out board) of the PSHL and above the waterline. This valve does not have to be actuated. Install an actuated, fail-safe-closed GLIV on the gas lift supply pipeline near the wellhead to provide the dual function of containing annular pressure and shutting off the gas lift supply gas. If your subsea trees or tubing head is equipped with an annulus master valve (AMV) or an annulus wing valve (AWV), one of these may be designated as the GLIV. Consider installing the GLIV external to the subsea tree to facilitate repair and or replacement if necessary. upstream (in board) of the GLSDV flowline upstream (in board) of the FSV. downstream (out board) of the GLSDV. (i) Ensure that the gas-lift supply flowline from the gas-lift compressor to the GLSDV is pressure-rated for the MAOP of the pipeline riser. Ensure that any surface equipment associated with the gas-lift system is rated for the MAOP of the pipeline riser. (ii) Ensure that the gas-lift compressor discharge pressure never exceeds the MAOP of the pipeline riser. (iii) Suspend and seal the gas-lift flowline contained within the production riser in a flanged API Spec. 6A component such as an API Spec. 6A tubing head and tubing hanger or a component designed, constructed, tested, and installed to the requirements of API Spec. 6A. Ensure that all potential leak paths upstream or near the production riser BSDV on the platform provide the same level of safety and environmental protection as the production riser BSDV. In addition, ensure that this complete assembly is fire-rated for 30 minutes. Attach the GLSDV by flanged connection directly to the API Spec. 6A component used to suspend and seal the gas-lift line contained within the production riser. To facilitate the repair or replacement of the GLSDV or production riser BSDV, you may install a manual isolation valve between the GLSDV and the API Spec. 6A component used to suspend and seal the gas-lift line contained within the production riser, or outboard of the production riser BSDV and inboard of the API Spec. 6A component used to suspend and seal the gas-lift line contained within the production riser. Additional requirements tkelley on DSK3SPTVN1PROD with PROPOSALS 9. On page 52280, the second table should read as follows: Type of gas lift system Valve Allowable leakage rate (i) Gas Lifting a subsea pipeline, pipeline riser, or manifold via an external gas lift pipeline. GLSDV Zero leakage. .................................... VerDate Mar<15>2010 18:25 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00029 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM Testing frequency Monthly, not to exceed 6 weeks. 04SEP1 54430 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules Valve (iii) Gas lifting the pipeline riser via a gas lift line contained within the pipeline riser. Testing frequency N/A .................................................... Function tested quarterly, not to exceed 120 days. GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks. GLIV .... (ii) Gas Lifting a subsea well through the casing string via an external gas lift pipeline. Allowable leakage rate GLIV .... Type of gas lift system 400 cc per minute of liquid or 15 scf per minute of gas. Function tested quarterly, not to exceed 120 days. GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks. 10. On page 52281, the table should read as follows: Valve Allowable leakage rate Testing frequency (i) WISDV ........................................................... Zero leakage .................................................... Monthly, not to exceed 6 weeks. (ii) Surface-controlled SSSV or WIV .................. 400 cc per minute of liquid or .......................... 15 scf per minute of gas .................................. Semiannually, not to exceed 6 calendar months. 11. On page 52282, the first table should read as follows: Item name Testing frequency, allowable leakage rates, and other requirements (i) Surface-controlled SSSVs (including devices installed in shut-in and injection wells). Not to exceed 6 months. Also test in place when first installed or reinstalled. If the device does not operate properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the device must be removed, repaired, and reinstalled or replaced. Testing must be according to API RP 14B (ISO 10417:2004) (incorporated by reference as specified in § 250.198) to ensure proper operation. (ii) Subsurface-controlled SSSVs ....................... Not to exceed 6 months for valves not installed in a landing nipple and 12 months for valves installed in a landing nipple. The valve must be removed, inspected, and repaired or adjusted, as necessary, and reinstalled or replaced. (iii) Tubing plug ................................................... Not to exceed 6 months. Test by opening the well to possible flow. If a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the plug must be removed, repaired, and reinstalled, or replaced. An additional tubing plug may be installed in lieu of removal. (iv) Injection valves ............................................. Not to exceed 6 months. Test by opening the well to possible flow. If a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the valve must be removed, repaired and reinstalled, or replaced. 12. On page 52282, the second table should read as follows: Testing frequency and requirements (i) PSVs ............................................................... Once each 12 months, not to exceed 13 months between tests. Valve must either be benchtested or equipped to permit testing with an external pressure source. Weighted disc vent valves used as PSVs on atmospheric tanks may be disassembled and inspected in lieu of function testing. (ii) Automatic inlet SDVs that are actuated by a sensor on a vessel or compressor. tkelley on DSK3SPTVN1PROD with PROPOSALS Item name Once each calendar month, not to exceed 6 weeks between tests. (iii) SDVs in liquid discharge lines and actuated by vessel low-level sensors. Once each calendar month, not to exceed 6 weeks between tests. (iv) SSVs ............................................................. Once each calendar month, not to exceed 6 weeks between tests. Valves must be tested for both operation and leakage. You must test according to API RP 14H (incorporated by reference as specified in § 250.198). If an SSV does not operate properly or if any fluid flow is observed during the leakage test, the valve must be immediately repaired or replaced. VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00030 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54431 Item name Testing frequency and requirements (v) FSVs .............................................................. Once each calendar month, not to exceed 6 weeks between tests. All FSVs must be tested, including those installed on a host facility in lieu of being installed at a satellite well. You must test FSVs for leakage in accordance with the test procedure specified in API RP 14C, appendix D, section D4, table D2 subsection D (incorporated by reference as specified in § 250.198). If leakage measured exceeds a liquid flow of 400 cubic centimeters per minute or a gas flow of 15 cubic feet per minute, the FSV must be repaired or replaced. 13. On page 52283, the first table should read as follows: Item name Testing frequency and requirements (i) Pumps for firewater systems .......................... Must be inspected and operated according to API RP 14G, Section 7.2 (incorporated by reference as specified in § 250.198). (ii) Fire- (flame, heat, or smoke) detection systems. Must be tested for operation and recalibrated every 3 months provided that testing can be performed in a non-destructive manner. Open flame or devices operating at temperatures that could ignite a methane-air mixture must not be used. All combustible gas-detection systems must be calibrated every 3 months. (iii) ESD systems. ............................................... (A) Pneumatic based ESD systems must be tested for operation at least once each calendar month, not to exceed 6 weeks between tests. You must conduct the test by alternating ESD stations monthly to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation. (B) Electronic based ESD systems must be tested for operation at least once every three calendar months, not to exceed 120 days between tests. The test must be conducted by alternating ESD stations to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation. (C) Electronic/pneumatic based ESD systems must be tested for operation at least once every three calendar months, not to exceed 120 days between tests. The test must be conducted by alternating ESD stations to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation. (iv) TSH devices ................................................. Must be tested for operation at least once every 12 months, excluding those addressed in paragraph (b)(3)(v) of this section and those that would be destroyed by testing. Those that could be destroyed by testing must be visually inspected and the circuit tested for operations at least once every 12 months. (v) TSH shutdown controls installed on compressor installations that can be nondestructively tested. Must be tested every 6 months and repaired or replaced as necessary. (vi) Burner safety low .......................................... Must be tested at least once every 12 months. (vii) Flow safety low devices ............................... Must be tested at least once every 12 months. (viii) Flame, spark, and detonation arrestors ...... Must be visually inspected at least once every 12 months. (ix) Electronic pressure transmitters and level sensors: PSH and PSL; LSH and LSL. Must be tested at least once every 3 months, but no more than 120 days elapse between tests. (x) Pneumatic/electronic switch PSH and PSL; pneumatic/electronic switch/electric analog with mechanical linkage LSH and LSL controls. Must be tested at least once each calendar month, but with no more than 6 weeks elapsed time between tests. 14. On page 52283, the second table should read as follows: tkelley on DSK3SPTVN1PROD with PROPOSALS Item name Testing frequency, allowable leakage rates, and other requirements (i) Surface-controlled SSSVs (including devices installed in shut-in and injection wells). Tested semiannually, not to exceed 6 months. If the device does not operate properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the device must be removed, repaired, and reinstalled or replaced. Testing must be according to API RP 14B (ISO 10417:2004) (incorporated by reference as specified in § 250.198) to ensure proper operation, or as approved in your DWOP. VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 PO 00000 Frm 00031 Fmt 4702 Sfmt 4702 E:\FR\FM\04SEP1.SGM 04SEP1 54432 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules Item name Testing frequency, allowable leakage rates, and other requirements (ii) USVs .................................................. Tested quarterly, not to exceed 120 days. If the device does not function properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the valve must be removed, repaired and reinstalled, or replaced. (iii) BSDVs ............................................... Tested monthly, not to exceed 6 weeks. Valves must be tested for both operation and leakage. You must test according to API RP 14H for SSVs (incorporated by reference as specified in § 250.198). If a BSDV does not operate properly or if any fluid flow is observed during the leakage test, the valve must be immediately repaired or replaced. (iv) Electronic ESD logic .......................... Tested monthly, not to exceed 6 weeks. (v) Electronic ESD function ..................... Tested quarterly, not to exceed 120 days. Shut-in at least one well during the ESD function test. If multiple wells are tied back to the same platform, a different well should be shut-in with each quarterly test. [FR Doc. C1–2013–19861 Filed 9–3–13; 8:45 am] BILLING CODE 1505–01–D DEPARTMENT OF HEALTH AND HUMAN SERVICES 42 CFR Part 84 [Docket No. CDC–2013–0017; NIOSH–250] Development of Inward Leakage Standards for Half-Mask Air-Purifying Particulate Respirators Centers for Disease Control and Prevention, HHS. ACTION: Request for comment and notice of public meeting. AGENCY: The National Institute for Occupational Safety and Health (NIOSH) of the Centers for Disease Control and Prevention (CDC) announces a public meeting concerning inward leakage performance requirements for the class of NIOSHcertified non-powered air-purifying particulate respirators approved as halffacepiece respirators for protection from particulate-only hazards. The purpose of this meeting is to share information and to seek stakeholder feedback, in identified topic areas, concerning the development of inward leakage performance standards. Questions concerning the identified topics of specific interest are included in this document. Attendance at the public meeting is not required to submit written responses to the questions in this notice. DATES: The public meeting will be held September 17, 2013, 1:00 p.m.–5:00 p.m. ET, or after the last public commenter has spoken. Stakeholder comments to the questions included in this document must be received by 11:59 p.m. ET on October 18, 2013. ADDRESSES: Meeting location: Bruceton Research Center, NIOSH National Personal Protective Technology tkelley on DSK3SPTVN1PROD with PROPOSALS SUMMARY: VerDate Mar<15>2010 18:08 Sep 03, 2013 Jkt 229001 Laboratory (NPPTL), 626 Cochrans Mill Road, Building 140, Multi-purpose Room, Pittsburgh, PA 15236. This meeting will also be available by remote access. Written Comments: You may submit comments by either of the following methods: • Federal eRulemaking Portal: http:// www.regulations.gov. Follow the instructions for submitting comments. • Mail: NIOSH Docket Office, Robert A. Taft Laboratories, MS–C34, 4676 Columbia Parkway, Cincinnati, OH 45226. Instructions: All submissions received must include the agency name (Centers for Disease Control and Prevention, HHS) and docket number (CDC–2013– 0017; NIOSH–250). All relevant comments, including any personal information provided, will be posted without change to http:// www.regulations.gov. Docket: For access to the docket to read background documents and submitted comments, go to http:// www.regulations.gov. FOR FURTHER INFORMATION CONTACT: Colleen Miller, NIOSH National Personal Protective Technology Laboratory (NPPTL), 626 Cochrans Mill Road, Pittsburgh, PA 15236 (412) 386– 4956 or (412) 386–5200 (these are not toll free numbers). SUPPLEMENTARY INFORMATION: I. Background Testing, quality control, and other requirements under 42 CFR Part 84 are intended to ensure that respirators supplied to U.S. workers provide effective protection when properly employed within a complete respiratory protection program, as specified under MSHA and OSHA regulations. NIOSH requirements governing approval of half-mask air-purifying particulate respirators, those defined in this notice, are principally specified in Part 84, under Subpart K—Non-Powered Air- PO 00000 Frm 00032 Fmt 4702 Sfmt 4702 Purifying Particulate Respirators. The performance of the respirator’s facepiece-to-face seal and other potential sources of inward leakage for this type of respirator are important to determine how much unfiltered contaminated air the worker might inhale. The facepiece-to-face seal leakage can be substantial in the case of a poorly fitting respirator. Effective fit testing technology and procedures exist to ensure that half-mask respirators approved by NIOSH under Subpart K of Part 84 have adequately performing facepiece-to-face seals. The purpose of this notice is to solicit stakeholder feedback regarding standards for inward leakage testing. NIOSH believes that the employee is more likely to achieve a good fit from a respirator design that has been demonstrated to achieve a specified minimum level of performance during certification testing. Accordingly, NIOSH initiated rulemaking activities to establish inward leakage performance requirements for NIOSH-approved particulate filtering respirators by publishing a notice of proposed rulemaking (NPRM) in the Federal Register on October 30, 2009 [74 FR 56141]. The public comment period for the rulemaking closed originally on December 28, 2009 but was subsequently extended upon request by stakeholders to September 30, 2010. Public meetings were held on December 3, 2009 and July 29, 2010 to allow stakeholders to share feedback on the proposed rule, including preliminary results of their independently completed or ongoing research. NIOSH reviewed all comments submitted by stakeholders and is considering them in the development of a revised inward leakage standard. II. Test Panel History Although NIOSH requires adequate facepiece-to-face seals for other types of respirators under Part 84, such requirements have not been applied to E:\FR\FM\04SEP1.SGM 04SEP1

Agencies

[Federal Register Volume 78, Number 171 (Wednesday, September 4, 2013)]
[Proposed Rules]
[Pages 54417-54432]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: C1-2013-19861]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

[Docket ID: BSEE-2012-0005; 13XE1700DX EX1SF0000.DAQ000 EEEE500000]
RIN 1014-AA10


Oil and Gas and Sulphur Operations on the Outer Continental 
Shelf--Oil and Gas Production Safety Systems

Correction

    In proposed rule document 2013-19861, appearing on pages 52240 
through 52284 in the issue of Thursday, August 22, 2013, make the 
following corrections:
    1. On pages 52241 through 52242, the table should read as follows:

------------------------------------------------------------------------
           Current regulation                     Proposed rule
------------------------------------------------------------------------
Sec.   250.800 General requirements....  Sec.   250.800 General.
------------------------------------------------------------------------
250.801 Subsurface safety devices......  Sec.   250.810 Dry tree
                                          subsurface safety devices--
                                          general.
                                        --------------------------------
                                         Sec.   250.811 Specifications
                                          for subsurface safety valves
                                          (SSSVs)--dry trees.
                                        --------------------------------
                                         Sec.   250.812 Surface-
                                          controlled SSSVs--dry trees.
                                        --------------------------------
                                         Sec.   250.813 Subsurface-
                                          controlled SSSVs.
                                        --------------------------------
                                         Sec.   250.814 Design,
                                          installation, and operation of
                                          SSSVs--dry trees.
                                        --------------------------------
                                         Sec.   250.815 Subsurface
                                          safety devices in shut-in
                                          wells--dry trees.
                                        --------------------------------
                                         Sec.   250.816 Subsurface
                                          safety devices in injection
                                          wells--dry trees.
                                        --------------------------------
                                         Sec.   250.817 Temporary
                                          removal of subsurface safety
                                          devices for routine
                                          operations.
                                        --------------------------------
                                         Sec.   250.818 Additional
                                          safety equipment--dry trees.
                                        --------------------------------
                                         Sec.   250.821 Emergency
                                          action.
                                        --------------------------------
                                         Sec.   250.825 Subsea tree
                                          subsurface safety devices--
                                          general.
                                        --------------------------------
                                         Sec.   250.826 Specifications
                                          for SSSVs--subsea trees.
                                        --------------------------------
                                         Sec.   250.827 Surface-
                                          controlled SSSVs--subsea
                                          trees.
                                        --------------------------------
                                         Sec.   250.828 Design,
                                          installation, and operation of
                                          SSSVs--subsea trees.
                                        --------------------------------
                                         Sec.   250.829 Subsurface
                                          safety devices in shut-in
                                          wells--subsea trees.
                                        --------------------------------
                                         Sec.   250.830 Subsurface
                                          safety devices in injection
                                          wells--subsea trees.
                                        --------------------------------
                                         Sec.   250.832 Additional
                                          safety equipment--subsea
                                          trees.
                                        --------------------------------
                                         Sec.   250.837 Emergency action
                                          and safety system shutdown.
------------------------------------------------------------------------
Sec.   250.802 Design, installation,     Sec.   250.819 Specification
 and operation of surface production-     for surface safety valves
 safety systems.                          (SSVs).
                                        --------------------------------
                                         Sec.   250.820 Use of SSVs.
                                        --------------------------------
                                         Sec.   250.833 Specification
                                          for underwater safety valves
                                          (USVs).
                                        --------------------------------
                                         Sec.   250.834 Use of USVs.
                                        --------------------------------
                                         Sec.   250.840 Design,
                                          installation, and maintenance--
                                          general.
                                        --------------------------------
                                         Sec.   250.841 Platforms.
                                        --------------------------------

[[Page 54418]]

 
                                         Sec.   250.842 Approval of
                                          safety systems design and
                                          installation features.
------------------------------------------------------------------------
Sec.   250.803 Additional production     Sec.   250.850 Production
 system requirements.                     system requirements--general.
                                        --------------------------------
                                         Sec.   250.851 Pressure vessels
                                          (including heat exchangers)
                                          and fired vessels.
                                        --------------------------------
                                         Sec.   250.852 Flowlines/
                                          Headers.
                                        --------------------------------
                                         Sec.   250.853 Safety sensors.
                                        --------------------------------
                                         Sec.   250.855 Emergency
                                          shutdown (ESD) system.
                                        --------------------------------
                                         Sec.   250.856 Engines.
                                        --------------------------------
                                         Sec.   250.857 Glycol
                                          dehydration units.
                                        --------------------------------
                                         Sec.   250.858 Gas compressors.
                                        --------------------------------
                                         Sec.   250.859 Firefighting
                                          systems.
                                        --------------------------------
                                         Sec.   250.862 Fire and gas-
                                          detection systems.
                                        --------------------------------
                                         Sec.   250.863 Electrical
                                          equipment.
                                        --------------------------------
                                         Sec.   250.864 Erosion.
                                        --------------------------------
                                         Sec.   250.869 General platform
                                          operations.
                                        --------------------------------
                                         Sec.   250.871 Welding and
                                          burning practices and
                                          procedures.
------------------------------------------------------------------------
Sec.   250.804 Production safety-system  Sec.   250.880 Production
 testing and records.                     safety system testing.
                                        --------------------------------
                                         Sec.   250.890 Records.
------------------------------------------------------------------------
Sec.   250.805 Safety device training..  Sec.   250.891 Safety device
                                          training.
------------------------------------------------------------------------
Sec.   250.806 Safety and pollution      Sec.   250.801 Safety and
 prevention equipment quality assurance   pollution prevention equipment
 requirements.                            (SPPE) certification.
                                        --------------------------------
                                         Sec.   250.802 Requirements for
                                          SPPE.
------------------------------------------------------------------------
Sec.   250.807 Additional requirements   Sec.   250.804 Additional
 for subsurface safety valves and         requirements for subsurface
 related equipment installed in high      safety valves (SSSVs) and
 pressure high temperature (HPHT)         related equipment installed in
 environments.                            high pressure high temperature
                                          (HPHT) environments.
------------------------------------------------------------------------
Sec.   250.808 Hydrogen sulfide........  Sec.   250.805 Hydrogen
                                          sulfide.
------------------------------------------------------------------------
              New Sections               Sec.   250.803 What SPPE
                                          failure reporting procedures
                                          must I follow?
                                        --------------------------------
                                         Sec.   250.831 Alteration or
                                          disconnection of subsea
                                          pipeline or umbilical.
                                        --------------------------------
                                         Sec.   250.835 Specification
                                          for all boarding shut down
                                          valves (BSDV) associated with
                                          subsea systems.
                                        --------------------------------
                                         Sec.   250.836 Use of BSDVs.
                                        --------------------------------
                                         Sec.   250.838 What are the
                                          maximum allowable valve
                                          closure times and hydraulic
                                          bleeding requirements for an
                                          electro-hydraulic control
                                          system?
                                        --------------------------------
                                         Sec.   250.839 What are the
                                          maximum allowable valve
                                          closure times and hydraulic
                                          bleeding requirements for a
                                          direct-hydraulic control
                                          system?
                                        --------------------------------
                                         Sec.   250.854 Floating
                                          production units equipped with
                                          turrets and turret mounted
                                          systems.
                                        --------------------------------
                                         Sec.   250.860 Chemical
                                          firefighting system.
                                        --------------------------------
                                         Sec.   250.861 Foam
                                          firefighting system.
                                        --------------------------------
                                         Sec.   250.865 Surface pumps.
                                        --------------------------------
                                         Sec.   250.866 Personal safety
                                          equipment.
                                        --------------------------------

[[Page 54419]]

 
                                         Sec.   250.867 Temporary
                                          quarters and temporary
                                          equipment.
                                        --------------------------------
                                         Sec.   250.868 Non-metallic
                                          piping.
                                        --------------------------------
                                         Sec.   250.870 Time delays on
                                          pressure safety low (PSL)
                                          sensors.
                                        --------------------------------
                                         Sec.   250.872 Atmospheric
                                          vessels.
                                        --------------------------------
                                         Sec.   250.873 Subsea gas lift
                                          requirements.
                                        --------------------------------
                                         Sec.   250.874 Subsea water
                                          injection systems.
                                        --------------------------------
                                         Sec.   250.875 Subsea pump
                                          systems.
                                        --------------------------------
                                         Sec.   250.876 Fired and
                                          Exhaust Heated Components.
------------------------------------------------------------------------

    2. On page 52251, the table should read as follows:
    [GRAPHIC] [TIFF OMITTED] TP04SE13.001
    
    3. On page 52254, Table 2 should read as follows:

[[Page 54420]]

[GRAPHIC] [TIFF OMITTED] TP04SE13.002

    4. On pages 52256 through 52260, the table should read as follows:

[[Page 54421]]

[GRAPHIC] [TIFF OMITTED] TP04SE13.003


[[Page 54422]]


[GRAPHIC] [TIFF OMITTED] TP04SE13.004


[[Page 54423]]


[GRAPHIC] [TIFF OMITTED] TP04SE13.005


[[Page 54424]]


[GRAPHIC] [TIFF OMITTED] TP04SE13.006


[[Page 54425]]


[GRAPHIC] [TIFF OMITTED] TP04SE13.007

BILLING CODE 1505-01-C
    5. On page 52271, the table should read as follows:

------------------------------------------------------------------------
                                          Details and/or additional
          You must submit:                      requirements:
------------------------------------------------------------------------
(1) A schematic piping and           Showing the following:
 instrumentation diagram.
                                     (i) Well shut-in tubing pressure;
                                     (ii) Piping specification breaks,
                                      piping sizes;
                                     (iii) Pressure relief valve set
                                      points;
                                     (iv) Size, capacity, and design
                                      working pressures of separators,
                                      flare scrubbers, heat exchangers,
                                      treaters, storage tanks,
                                      compressors and metering devices;

[[Page 54426]]

 
                                     (v) Size, capacity, design working
                                      pressures, and maximum discharge
                                      pressure of hydrocarbon-handling
                                      pumps;
                                     (vi) size, capacity, and design
                                      working pressures of hydrocarbon-
                                      handling vessels, and chemical
                                      injection systems handling a
                                      material having a flash point
                                      below 100 degrees Fahrenheit for a
                                      Class I flammable liquid as
                                      described in API RP 500 and 505
                                      (both incorporated by reference as
                                      specified in Sec.   250.198).
                                     (vii) Size and maximum allowable
                                      working pressures as determined in
                                      accordance with API RP 14E,
                                      Recommended Practice for Design
                                      and Installation of Offshore
                                      Production Platform Piping Systems
                                      (incorporated by reference as
                                      specified in Sec.   250.198).
------------------------------------------------------------------------
(2) A safety analysis flow diagram   if processing components are used,
 (API RP 14C, Appendix E) and the     other than those for which Safety
 related Safety Analysis Function     Analysis Checklists are included
 Evaluation (SAFE) chart (API RP      in API RP 14C, you must use the
 14C, subsection 4.3.3)               same analysis technique and
 (incorporated by reference as        documentation to determine the
 specified in Sec.   250.198).        effects and requirements of these
                                      components upon the safety system.
------------------------------------------------------------------------
(3) Electrical system information,   (i) A plan for each platform deck
 including.                           and outlining all classified
                                      areas. You must classify areas
                                      according to API RP 500,
                                      Recommended Practice for
                                      Classification of Locations for
                                      Electrical Installations at
                                      Petroleum Facilities Classified as
                                      Class I, Division 1 and Division
                                      2; or API RP 505, Recommended
                                      Practice for Classification of
                                      Locations for Electrical
                                      Installations at Petroleum
                                      Facilities Classified as Class I,
                                      Zone 0, Zone 1, and Zone 2 (both
                                      incorporated by reference as
                                      specified in Sec.   250.198).
                                     (ii) Identification of all areas
                                      where potential ignition sources,
                                      including non-electrical ignition
                                      sources, are to be installed
                                      showing:
                                       (A) All major production
                                     equipment, wells, and other
                                     significant hydrocarbon sources,
                                     and a description of the type of
                                     decking, ceiling, and walls (e.g.,
                                     grating or solid) and firewalls
                                     and;
                                       (B) the location of generators,
                                     control rooms, panel boards, major
                                     cabling/conduit routes, and
                                     identification of the primary
                                     wiring method (e.g., type cable,
                                     conduit, wire) and;
                                     (iii) one-line electrical drawings
                                      of all electrical systems
                                      including the safety shutdown
                                      system. You must also include a
                                      functional legend.
------------------------------------------------------------------------
(4) Schematics of the fire and gas-  showing a functional block diagram
 detection systems.                   of the detection system, including
                                      the electrical power supply and
                                      also including the type, location,
                                      and number of detection sensors;
                                      the type and kind of alarms,
                                      including emergency equipment to
                                      be activated; the method used for
                                      detection; and the method and
                                      frequency of calibration.
------------------------------------------------------------------------
(5) The service fee listed in Sec.   The fee you must pay will be
  250.125..                           determined by the number of
                                      components involved in the review
                                      and approval process.
------------------------------------------------------------------------

    6. On page 52272, the table should read as follows:

------------------------------------------------------------------------
             Item name                Applicable codes and requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels       (i) Must be designed, fabricated,
 where the operating pressure is or   and code stamped according to
 will be 15 pounds per square inch    applicable provisions of sections
 gauge (psig) or greater.             I, IV, and VIII of the ANSI/ASME
                                      Boiler and Pressure Vessel Code.
                                     (ii) Must be repaired, maintained,
                                      and inspected in accordance with
                                      API 510, Pressure Vessel
                                      Inspection Code: In-Service
                                      Inspection, Rating, Repair, and
                                      Alteration, Downstream Segment
                                      (incorporated by reference as
                                      specified in Sec.   250.198).
------------------------------------------------------------------------
(2) Pressure and fired vessels       Must employ a safety analysis
 (such as flare and vent scrubbers)   checklist in the design of each
 where the operating pressure is or   component. These vessels do not
 will be at least 5 psig and less     need to be ASME Code stamped as
 than 15 psig.                        pressure vessels.
------------------------------------------------------------------------
(3) Pressure and fired vessels       Are not subject to the requirements
 where the operating pressure is or   of paragraphs (a)(1) and (a)(2).
 will be less than 5 psig.
------------------------------------------------------------------------
(4) Existing uncoded Pressure and    Must be justified and approval
 fired vessels (i) in use on the      obtained from the District Manager
 effective date of the final rule;    for their continued use beyond 18
 (ii) with an operating pressure of   months from the effective date of
 5 psig or greater; and (iii) that    the final rule.
 are not code stamped in accordance
 with the ANSI/ASME Boiler and
 Pressure Vessel Code.
------------------------------------------------------------------------

[[Page 54427]]

 
(5) Pressure relief valves.........  (i) Must be designed and installed
                                      according to applicable provisions
                                      of sections I, IV, and VIII of the
                                      ASME Boiler and Pressure Vessel
                                      Code.
                                     (ii) Must conform to the valve
                                      sizing and pressure-relieving
                                      requirements specified in these
                                      documents, but (except for
                                      completely redundant relief
                                      valves), must be set no higher
                                      than the maximum-allowable working
                                      pressure of the vessel.
                                     (iii) And vents must be positioned
                                      in such a way as to prevent fluid
                                      from striking personnel or
                                      ignition sources.
(6) Steam generators operating at    Must be equipped with a level
 less than 15 psig.                   safety low (LSL) sensor which will
                                      shut off the fuel supply when the
                                      water level drops below the
                                      minimum safe level.
------------------------------------------------------------------------
(7) Steam generators operating at    (i) Must be equipped with a level
 15 psig or greater.                  safety low (LSL) sensor which will
                                      shut off the fuel supply when the
                                      water level drops below the
                                      minimum safe level.
                                     (ii) You must also install a water-
                                      feeding device that will
                                      automatically control the water
                                      level except when closed loop
                                      systems are used for steam
                                      generation.
------------------------------------------------------------------------

    7. On pages 52275 through 52276, the table should read as follows:

------------------------------------------------------------------------
     For the use of a chemical
  firefighting system on major and
  minor manned platforms, you must             Including . . .
 provide the following in your risk
          assessment . . .
------------------------------------------------------------------------
(i) Platform description...........  (A) The type and quantity of
                                      hydrocarbons (i.e., natural gas,
                                      oil) that are produced, handled,
                                      stored, or processed at the
                                      facility.
                                     (B) The capacity of any tanks on
                                      the facility that you use to store
                                      either liquid hydrocarbons or
                                      other flammable liquids.
                                     (C) The total volume of flammable
                                      liquids (other than produced
                                      hydrocarbons) stored on the
                                      facility in containers other than
                                      bulk storage tanks. Include
                                      flammable liquids stored in paint
                                      lockers, storerooms, and drums.
                                     (D) If the facility is manned,
                                      provide the maximum number of
                                      personnel on board and the
                                      anticipated length of their stay.
                                     (E) If the facility is unmanned,
                                      provide the number of days per
                                      week the facility will be visited,
                                      the average length of time spent
                                      on the facility per day, the mode
                                      of transportation, and whether or
                                      not transportation will be
                                      available at the facility while
                                      personnel are on board.
                                     (F) A diagram that depicts:
                                      quarters location, production
                                      equipment location, fire
                                      prevention and control equipment
                                      location, lifesaving appliances
                                      and equipment location, and
                                      evacuation plan escape routes from
                                      quarters and all manned working
                                      spaces to primary evacuation
                                      equipment.
------------------------------------------------------------------------
(ii) Hazard assessment (facility     (A) Identification of all likely
 specific).                           fire initiation scenarios
                                      (including those resulting from
                                      maintenance and repair
                                      activities). For each scenario,
                                      discuss its potential severity and
                                      identify the ignition and fuel
                                      sources.
                                     (B) Estimates of the fire/radiant
                                      heat exposure that personnel could
                                      be subjected to. Show how you have
                                      considered designated muster areas
                                      and evacuation routes near fuel
                                      sources and have verified proper
                                      flare boom sizing for radiant heat
                                      exposure.
------------------------------------------------------------------------
(iii) Human factors assessment (not  (A) Descriptions of the fire-
 facility specific).                  related training your employees
                                      and contractors have received.
                                      Include details on the length of
                                      training, whether the training was
                                      hands-on or classroom, the
                                      training frequency, and the topics
                                      covered during the training.
                                     (B) Descriptions of the training
                                      your employees and contractors
                                      have received in fire prevention,
                                      control of ignition sources, and
                                      control of fuel sources when the
                                      facility is occupied.
                                     (C) Descriptions of the
                                      instructions and procedures you
                                      have given to your employees and
                                      contractors on the actions they
                                      should take if a fire occurs.
                                      Include those instructions and
                                      procedures specific to evacuation.
                                      State how you convey this
                                      information to your employees and
                                      contractor on the platform.
------------------------------------------------------------------------

[[Page 54428]]

 
(iv) Evacuation assessment           (A) A general discussion of your
 (facility specific).                 evacuation plan. Identify your
                                      muster areas (if applicable), both
                                      the primary and secondary
                                      evacuation routes, and the means
                                      of evacuation for both.
                                     (B) Description of the type,
                                      quantity, and location of
                                      lifesaving appliances available on
                                      the facility. Show how you have
                                      ensured that lifesaving appliances
                                      are located in the near vicinity
                                      of the escape routes.
                                     (C) Description of the types and
                                      availability of support vessels,
                                      whether the support vessels are
                                      equipped with a fire monitor, and
                                      the time needed for support
                                      vessels to arrive at the facility.
                                     (D) Estimates of the worst case
                                      time needed for personnel to
                                      evacuate the facility should a
                                      fire occur.
------------------------------------------------------------------------
(v) Alternative protection           (A) Discussion of the reasons you
 assessment.                          are proposing to use an
                                      alternative fire prevention and
                                      control system.
                                     (B) Lists of the specific standards
                                      used to design the system, locate
                                      the equipment, and operate the
                                      equipment/system.
                                     (C) Description of the proposed
                                      alternative fire prevention and
                                      control system/equipment. Provide
                                      details on the type, size, number,
                                      and location of the prevention and
                                      control equipment.
                                     (D) Description of the testing,
                                      inspection, and maintenance
                                      program you will use to maintain
                                      the fire prevention and control
                                      equipment in an operable
                                      condition. Provide specifics
                                      regarding the type of inspection,
                                      the personnel who conduct the
                                      inspections, the inspection
                                      procedures, and documentation and
                                      recordkeeping.
------------------------------------------------------------------------
(vi) Conclusion....................  A summary of your technical
                                      evaluation showing that the
                                      alternative system provides an
                                      equivalent level of personnel
                                      protection for the specific
                                      hazards located on the facility.
------------------------------------------------------------------------

    8. On pages 52279 through 52280, the table spanning those two pages 
should read as follows:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Then you must install a . . .
                                 -------------------------------------------------------------------------------------
                                    API Spec 6A and API
 If your subsea gas lift system       Spec 6AV1 (both
introduces the lift gas to the .      incorporated by        FSV on the gas-                         API Spec 6A and        Additional requirements
               . .                 reference as specified      lift supply      PSHL on the gas-      API Spec 6AV1
                                  in Sec.   250.198) gas-    pipeline . . .     lift supply . . .   manual isolation
                                    lift shutdown valve                                                valve . . .
                                     (GLSDV), and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea Pipelines, Pipeline    meet all of the          upstream (in        pipeline upstream   downstream (out     (i) Ensure that the MAOP of a
 Risers, or Manifolds via an       requirements for the     board) of the       (in board) of the   board) of the       subsea gas lift supply pipeline
 External Gas Lift Pipeline.       BSDV described in        GLSDV               GLSDV               PSHL and above      is equal to the MAOP of the
                                   250.835 and 250.836 on                                           the waterline.      production pipeline. an actuated
                                   the gas-lift supply                                              This valve does     fail-safe close gas-lift
                                   pipeline.                                                        not have to be      isolation valve (GLIV) located
                                                                                                    actuated.           at the point of intersection
                                                                                                                        between the gas lift supply
                                                                                                                        pipeline and the production
                                                                                                                        pipeline, pipeline riser, or
                                                                                                                        manifold. (ii) Install an
                                                                                                                        actuated fail-safe close gas-
                                                                                                                        lift isolation valve (GLIV)
                                                                                                                        located at the point of
                                                                                                                        intersection between the gas
                                                                                                                        lift supply pipeline and the
                                                                                                                        production pipeline, pipeline
                                                                                                                        riser, or manifold. Install the
                                                                                                                        GLIV downstream of the
                                                                                                                        underwater safety valve(s) (USV)
                                                                                                                        and/or AIV(s).
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 54429]]

 
(2) Subsea Well(s) through the    Locate the GLSDV within  on the platform     pipeline on the     downstream (out     Install an actuated, fail-safe-
 Casing String via an External     10 feet of the first     upstream (in        platform            board) of the       closed GLIV on the gas lift
 Gas Lift Pipeline.                of access to the gas-    board) of the       downstream (out     PSHL and above      supply pipeline near the
                                   lift riser or topsides   GLSDV               board) of the       the waterline.      wellhead to provide the dual
                                   umbilical termination                        GLSDV.              This valve does     function of containing annular
                                   assembly (TUTA) (i.e.,                                           not have to be      pressure and shutting off the
                                   within 10 feet of the                                            actuated.           gas lift supply gas. If your
                                   edge of the platform                                                                 subsea trees or tubing head is
                                   if the GLSDV is                                                                      equipped with an annulus master
                                   horizontal, or within                                                                valve (AMV) or an annulus wing
                                   10 feet above the                                                                    valve (AWV), one of these may be
                                   first accessible                                                                     designated as the GLIV. Consider
                                   working deck,                                                                        installing the GLIV external to
                                   excluding the boat                                                                   the subsea tree to facilitate
                                   landing and above the                                                                repair and or replacement if
                                   splash zone, if the                                                                  necessary.
                                   GLSDV is in the
                                   vertical run of a
                                   riser, or within 10
                                   feet of the TUTA if
                                   using an umbilical).
(3) Pipeline Risers via a Gas-    locate the GLSDV within  upstream (in        flowline upstream   downstream (out     (i) Ensure that the gas-lift
 Lift Line Contained within the    10 feet of the first     board) of the       (in board) of the   board) of the       supply flowline from the gas-
 Pipeline Riser                    of access to the gas-    GLSDV               FSV.                GLSDV.              lift compressor to the GLSDV is
                                   lift riser or TUTA                                                                   pressure-rated for the MAOP of
                                   (i.e., within 10 feet                                                                the pipeline riser. Ensure that
                                   of the edge of the                                                                   any surface equipment associated
                                   platform if the GLSDV                                                                with the gas-lift system is
                                   is horizontal, or                                                                    rated for the MAOP of the
                                   within 10 feet above                                                                 pipeline riser. (ii) Ensure that
                                   the first accessible                                                                 the gas-lift compressor
                                   working deck,                                                                        discharge pressure never exceeds
                                   excluding the boat                                                                   the MAOP of the pipeline riser.
                                   landing and above the                                                                (iii) Suspend and seal the gas-
                                   splash zone, if the                                                                  lift flowline contained within
                                   GLSDV is in the                                                                      the production riser in a
                                   vertical run of a                                                                    flanged API Spec. 6A component
                                   riser, or within 10                                                                  such as an API Spec. 6A tubing
                                   feet of the TUTA if                                                                  head and tubing hanger or a
                                   using an umbilical).                                                                 component designed, constructed,
                                                                                                                        tested, and installed to the
                                                                                                                        requirements of API Spec. 6A.
                                                                                                                        Ensure that all potential leak
                                                                                                                        paths upstream or near the
                                                                                                                        production riser BSDV on the
                                                                                                                        platform provide the same level
                                                                                                                        of safety and environmental
                                                                                                                        protection as the production
                                                                                                                        riser BSDV. In addition, ensure
                                                                                                                        that this complete assembly is
                                                                                                                        fire-rated for 30 minutes.
                                                                                                                        Attach the GLSDV by flanged
                                                                                                                        connection directly to the API
                                                                                                                        Spec. 6A component used to
                                                                                                                        suspend and seal the gas-lift
                                                                                                                        line contained within the
                                                                                                                        production riser. To facilitate
                                                                                                                        the repair or replacement of the
                                                                                                                        GLSDV or production riser BSDV,
                                                                                                                        you may install a manual
                                                                                                                        isolation valve between the
                                                                                                                        GLSDV and the API Spec. 6A
                                                                                                                        component used to suspend and
                                                                                                                        seal the gas-lift line contained
                                                                                                                        within the production riser, or
                                                                                                                        outboard of the production riser
                                                                                                                        BSDV and inboard of the API
                                                                                                                        Spec. 6A component used to
                                                                                                                        suspend and seal the gas-lift
                                                                                                                        line contained within the
                                                                                                                        production riser.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    9. On page 52280, the second table should read as follows:

----------------------------------------------------------------------------------------------------------------
       Type of gas lift system               Valve          Allowable leakage rate         Testing frequency
----------------------------------------------------------------------------------------------------------------
(i) Gas Lifting a subsea pipeline,     GLSDV............  Zero leakage..............  Monthly, not to exceed 6
 pipeline riser, or manifold via an                                                    weeks.
 external gas lift pipeline.
                                      --------------------------------------------------------------------------

[[Page 54430]]

 
                                       GLIV.............  N/A.......................  Function tested quarterly,
                                                                                       not to exceed 120 days.
----------------------------------------------------------------------------------------------------------------
(ii) Gas Lifting a subsea well         GLSDV............  Zero leakage..............  Monthly, not to exceed 6
 through the casing string via an                                                      weeks.
 external gas lift pipeline.
                                      --------------------------------------------------------------------------
                                       GLIV.............  400 cc per minute of        Function tested quarterly,
                                                           liquid or 15 scf per        not to exceed 120 days.
                                                           minute of gas.
----------------------------------------------------------------------------------------------------------------
(iii) Gas lifting the pipeline riser   GLSDV............  Zero leakage..............  Monthly, not to exceed 6
 via a gas lift line contained within                                                  weeks.
 the pipeline riser.
----------------------------------------------------------------------------------------------------------------

    10. On page 52281, the table should read as follows:

------------------------------------------------------------------------
                                Allowable leakage
            Valve                     rate            Testing frequency
------------------------------------------------------------------------
(i) WISDV...................  Zero leakage........  Monthly, not to
                                                     exceed 6 weeks.
------------------------------------------------------------------------
(ii) Surface-controlled SSSV  400 cc per minute of  Semiannually, not to
 or WIV.                       liquid or.            exceed
                              15 scf per minute of  6 calendar months.
                               gas.
------------------------------------------------------------------------

    11. On page 52282, the first table should read as follows:

----------------------------------------------------------------------------------------------------------------
                                              Testing frequency, allowable leakage rates, and other requirements
                  Item name
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including       Not to exceed 6 months. Also test in place when first installed or
 devices installed in shut-in and injection    reinstalled. If the device does not operate properly, or if a
 wells).                                       liquid leakage rate > 400 cubic centimeters per minute or a gas
                                               leakage rate > 15 cubic feet per minute is observed, the device
                                               must be removed, repaired, and reinstalled or replaced. Testing
                                               must be according to API RP 14B (ISO 10417:2004) (incorporated by
                                               reference as specified in Sec.   250.198) to ensure proper
                                               operation.
----------------------------------------------------------------------------------------------------------------
(ii) Subsurface-controlled SSSVs............  Not to exceed 6 months for valves not installed in a landing
                                               nipple and 12 months for valves installed in a landing nipple.
                                               The valve must be removed, inspected, and repaired or adjusted,
                                               as necessary, and reinstalled or replaced.
----------------------------------------------------------------------------------------------------------------
(iii) Tubing plug...........................  Not to exceed 6 months. Test by opening the well to possible flow.
                                               If a liquid leakage rate > 400 cubic centimeters per minute or a
                                               gas leakage rate > 15 cubic feet per minute is observed, the plug
                                               must be removed, repaired, and reinstalled, or replaced. An
                                               additional tubing plug may be installed in lieu of removal.
----------------------------------------------------------------------------------------------------------------
(iv) Injection valves.......................  Not to exceed 6 months. Test by opening the well to possible flow.
                                               If a liquid leakage rate > 400 cubic centimeters per minute or a
                                               gas leakage rate > 15 cubic feet per minute is observed, the
                                               valve must be removed, repaired and reinstalled, or replaced.
----------------------------------------------------------------------------------------------------------------

    12. On page 52282, the second table should read as follows:

----------------------------------------------------------------------------------------------------------------
                  Item name                                   Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) PSVs....................................  Once each 12 months, not to exceed 13 months between tests. Valve
                                               must either be bench-tested or equipped to permit testing with an
                                               external pressure source. Weighted disc vent valves used as PSVs
                                               on atmospheric tanks may be disassembled and inspected in lieu of
                                               function testing.
----------------------------------------------------------------------------------------------------------------
(ii) Automatic inlet SDVs that are actuated   Once each calendar month, not to exceed 6 weeks between tests.
 by a sensor on a vessel or compressor.
----------------------------------------------------------------------------------------------------------------
(iii) SDVs in liquid discharge lines and      Once each calendar month, not to exceed 6 weeks between tests.
 actuated by vessel low-level sensors.
----------------------------------------------------------------------------------------------------------------
(iv) SSVs...................................  Once each calendar month, not to exceed 6 weeks between tests.
                                               Valves must be tested for both operation and leakage. You must
                                               test according to API RP 14H (incorporated by reference as
                                               specified in Sec.   250.198). If an SSV does not operate properly
                                               or if any fluid flow is observed during the leakage test, the
                                               valve must be immediately repaired or replaced.
----------------------------------------------------------------------------------------------------------------

[[Page 54431]]

 
(v) FSVs....................................  Once each calendar month, not to exceed 6 weeks between tests. All
                                               FSVs must be tested, including those installed on a host facility
                                               in lieu of being installed at a satellite well. You must test
                                               FSVs for leakage in accordance with the test procedure specified
                                               in API RP 14C, appendix D, section D4, table D2 subsection D
                                               (incorporated by reference as specified in Sec.   250.198). If
                                               leakage measured exceeds a liquid flow of 400 cubic centimeters
                                               per minute or a gas flow of 15 cubic feet per minute, the FSV
                                               must be repaired or replaced.
----------------------------------------------------------------------------------------------------------------

    13. On page 52283, the first table should read as follows:

----------------------------------------------------------------------------------------------------------------
                  Item name                                   Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) Pumps for firewater systems.............  Must be inspected and operated according to API RP 14G, Section
                                               7.2 (incorporated by reference as specified in Sec.   250.198).
----------------------------------------------------------------------------------------------------------------
(ii) Fire- (flame, heat, or smoke) detection  Must be tested for operation and recalibrated every 3 months
 systems.                                      provided that testing can be performed in a non-destructive
                                               manner. Open flame or devices operating at temperatures that
                                               could ignite a methane-air mixture must not be used. All
                                               combustible gas-detection systems must be calibrated every 3
                                               months.
----------------------------------------------------------------------------------------------------------------
(iii) ESD systems...........................  (A) Pneumatic based ESD systems must be tested for operation at
                                               least once each calendar month, not to exceed 6 weeks between
                                               tests. You must conduct the test by alternating ESD stations
                                               monthly to close at least one wellhead SSV and verify a surface-
                                               controlled SSSV closure for that well as indicated by control
                                               circuitry actuation.
                                              (B) Electronic based ESD systems must be tested for operation at
                                               least once every three calendar months, not to exceed 120 days
                                               between tests. The test must be conducted by alternating ESD
                                               stations to close at least one wellhead SSV and verify a surface-
                                               controlled SSSV closure for that well as indicated by control
                                               circuitry actuation.
                                              (C) Electronic/pneumatic based ESD systems must be tested for
                                               operation at least once every three calendar months, not to
                                               exceed 120 days between tests. The test must be conducted by
                                               alternating ESD stations to close at least one wellhead SSV and
                                               verify a surface-controlled SSSV closure for that well as
                                               indicated by control circuitry actuation.
----------------------------------------------------------------------------------------------------------------
(iv) TSH devices............................  Must be tested for operation at least once every 12 months,
                                               excluding those addressed in paragraph (b)(3)(v) of this section
                                               and those that would be destroyed by testing. Those that could be
                                               destroyed by testing must be visually inspected and the circuit
                                               tested for operations at least once every 12 months.
----------------------------------------------------------------------------------------------------------------
(v) TSH shutdown controls installed on        Must be tested every 6 months and repaired or replaced as
 compressor installations that can be          necessary.
 nondestructively tested.
----------------------------------------------------------------------------------------------------------------
(vi) Burner safety low......................  Must be tested at least once every 12 months.
----------------------------------------------------------------------------------------------------------------
(vii) Flow safety low devices...............  Must be tested at least once every 12 months.
----------------------------------------------------------------------------------------------------------------
(viii) Flame, spark, and detonation           Must be visually inspected at least once every 12 months.
 arrestors.
----------------------------------------------------------------------------------------------------------------
(ix) Electronic pressure transmitters and     Must be tested at least once every 3 months, but no more than 120
 level sensors: PSH and PSL; LSH and LSL.      days elapse between tests.
----------------------------------------------------------------------------------------------------------------
(x) Pneumatic/electronic switch PSH and PSL;  Must be tested at least once each calendar month, but with no more
 pneumatic/electronic switch/electric analog   than 6 weeks elapsed time between tests.
 with mechanical linkage LSH and LSL
 controls.
----------------------------------------------------------------------------------------------------------------

    14. On page 52283, the second table should read as follows:

----------------------------------------------------------------------------------------------------------------
                                              Testing frequency, allowable leakage rates, and other requirements
                  Item name
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including       Tested semiannually, not to exceed 6 months. If the device does
 devices installed in shut-in and injection    not operate properly, or if a liquid leakage rate > 400 cubic
 wells).                                       centimeters per minute or a gas leakage rate > 15 cubic feet per
                                               minute is observed, the device must be removed, repaired, and
                                               reinstalled or replaced. Testing must be according to API RP 14B
                                               (ISO 10417:2004) (incorporated by reference as specified in Sec.
                                                250.198) to ensure proper operation, or as approved in your
                                               DWOP.
----------------------------------------------------------------------------------------------------------------

[[Page 54432]]

 
(ii) USVs...................................  Tested quarterly, not to exceed 120 days. If the device does not
                                               function properly, or if a liquid leakage rate > 400 cubic
                                               centimeters per minute or a gas leakage rate > 15 cubic feet per
                                               minute is observed, the valve must be removed, repaired and
                                               reinstalled, or replaced.
----------------------------------------------------------------------------------------------------------------
(iii) BSDVs.................................  Tested monthly, not to exceed 6 weeks. Valves must be tested for
                                               both operation and leakage. You must test according to API RP 14H
                                               for SSVs (incorporated by reference as specified in Sec.
                                               250.198). If a BSDV does not operate properly or if any fluid
                                               flow is observed during the leakage test, the valve must be
                                               immediately repaired or replaced.
----------------------------------------------------------------------------------------------------------------
(iv) Electronic ESD logic...................  Tested monthly, not to exceed 6 weeks.
----------------------------------------------------------------------------------------------------------------
(v) Electronic ESD function.................  Tested quarterly, not to exceed 120 days. Shut-in at least one
                                               well during the ESD function test. If multiple wells are tied
                                               back to the same platform, a different well should be shut-in
                                               with each quarterly test.
----------------------------------------------------------------------------------------------------------------

[FR Doc. C1-2013-19861 Filed 9-3-13; 8:45 am]
BILLING CODE 1505-01-D