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: https:// 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 https:// www.regulations.gov. Docket: For access to the docket to read background documents and submitted comments, go to https:// 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

DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement

[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:

[[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:

[[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

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