### 54417 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. [FR Doc. 2013–21610 Filed 9–3–13; 8:45 am] **BILLING CODE 4210–67–P 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**  § 250.800 General requirements ............................................................ § 250.800 General. 250.801 Subsurface safety devices ....................................................... § 250.810 Dry tree subsurface safety devices—general. § 250.811 Specifications for subsurface safety valves (SSSVs)—dry

trees. § 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 Additional safety equipment—dry trees. § 250.821 Emergency action. § 250.825 Subsea tree subsurface safety devices—general. § 250.826 Specifications for SSSVs—subsea trees. § 250.827 Surface-controlled SSSVs—subsea trees. § 250.828 Design, installation, and operation of SSSVs—subsea

trees. § 250.829 Subsurface safety devices in shut-in wells—subsea trees. § 250.830 Subsurface safety devices in injection wells—subsea trees. § 250.832 Additional safety equipment—subsea trees. § 250.837 Emergency action and safety system shutdown.§ 250.802 Design, installation, and operation of surface productionsafety systems. § 250.819 Specification for surface safety valves (SSVs).

§ 250.820 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 Platforms.


### 54418 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**Current regulation Proposed rule**  § 250.842 Approval of safety systems design and installation features. § 250.803 Additional production system requirements .......................... § 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. § 250.804 Production safety-system testing and records ...................... § 250.880 Production safety system testing. § 250.890 Records. § 250.805 Safety device training ............................................................ § 250.891 Safety device training.§ 250.806 Safety and pollution prevention equipment quality assurance requirements. § 250.801 Safety and pollution prevention equipment (SPPE) certification. § 250.802 Requirements for SPPE. § 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 Hydrogen sulfide ................................................................... § 250.805 Hydrogen sulfide. **New Sections** § 250.803 What SPPE failure reporting procedures must I follow? § 250.831 Alteration or disconnection of subsea pipeline or umbilical.§ 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? § 250.854 Floating production units equipped with turrets and turret

mounted systems. § 250.860 Chemical firefighting system. § 250.861 Foam firefighting system. § 250.865 Surface pumps. § 250.866 Personal safety equipment.


### 54419 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**Current regulation 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:

3. On page 52254, Table 2 should read as follows:


### 54420 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

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


### Citation 30 

### Hou'

# ~ AvmgeNo. Annual CFR 250, Reporting and Recordkeeping B 

### d ofAnnual Burden
I 

### Subpart A Requirement ur en Responses Hours
I 1 NEW: Demonstrate to us that by using 2 BAST the benefits are insufficient to justifY 5 I 

### justifications 10 the cost. Subtotal 2 responses 10 hours
I 

### Citation I 

### Average No. Annual Hour 30 CFR250 Reporting and Recordkeeping Burden ofAnnual Burden Subpart H Requirement Responses Hours and NTL(s) Non-Hour Cost Burdens* I 

### General Requirements 800(a) Requirements for your production safety Burden included with 0 system application. specific requirements I 

### below.

! 

### 800(a); Prior to production, request approval ofpre- 1 76 requests 76

880(a); production inspection; notifY BSEE 72 hours before commencement so we may witness preproduction test and conduct ins}Jection. 801(c) Request evaluation and approval [OORP] of 2 1 request 2 other quality assurance programs covering manufacture ofSPPE. 802(c)(1 ); NEW: Submit statement/certification for: Not considered IC under 5 0 852(e)(4); exposure functionality; pipe is suitable and CFR 1320.3(h)(1). 861(b); manufacturer has complied with IVA; suitable firefighting foam per original manufacturer specifications. 802(c)(5) NEW: Document all manufacturing, 2 I 30 60 traceability, quality control, and inspection documents requirements. Retain required documentation until 1 year after the date ofdecommissioning the**e~me!1t.** 

### 803(a) NEW: Within 30 days ofdiscovery and 2 10 reports 20 identification ofSPPE failure, provide a
I 

### written report ofequipment failure to manufacturer. I 803(b) NEW: Document and determine the results 5 10 50 I I 

### ofthe SPPE failure within 60-days and documents ! 

### I I 

### corrective action taken.

803(c) NEW: Submit [OORP] modified 2 I submittal 2 procedures you made ifnotified by manufacturer ofdesign changes or you changed operating or repair procedures as result ofa failure, within 30 days.

I 

### 804 Submit detailed info regarding installing Burdens are covered under 0 SSVs in an HPHT environment with your 30 CFR 250, Subparts D APD, APM, DWOP etc. and B, 1014-0018 and 1014-0024. 804(b); NEW: District Manager will approve on a Not considered IC per 5 0 i 

### 829(b), (c); case-by-case basis. CFR 1320.3(h)(6). I 841(b); !

### 54422 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules


I 810; 816;

825(a); 830;

I 814(a); 821;

I i 828(a); I 838(c)(3);

I 859(b);

1 870(b); rsI7(b);

i 869(a);

I
817(b)

817(c)

825(b); 831; 833; 837(c)(5); 838(c); 874(g)(2); 874(f); 

### Subtotal I 

### 128

i 

### responses Surface and Subsurface Safety Systems
- Dry Trees Submit request for a determination that a 5 % 41 wells well is incapable ofnatural**flow'~**____

# =
______--+

____'--

____ 1 VerifY the no-flow condition ofthe well y,. annually. Specific alternate approval requests requiring approval.

IdentifY well with sign on wellhead that subsurface safety device is removed; flag safety devices that are out ofservice; a visual indicator must be used to identify the bypassed safety device. Record removal of subsurface safety device.

1 Request alternate approval ofmaster valve

I [required to be submitted with an APM].



### Subsea and Subsurface Safety NEW: NotifY BSEE: (1) ifyou cannot test all valves and sensors; (2) 48 hours in advance ifmonitoring ability affected; (3) designating USV2 or another qualified valve; (4) resuming production; (5) 12 hours ofdetecting loss ofcommunication; immediately ifyou cannot meet value closure conditions. Burden covered under 30 CFR 250, subpart A, 1014- 0022.

Usual/customary safety procedure for removing or identifYing out-of-service safety devices.

Burden included in § 250.890 ofthis subpart. Burden covered under 30 CFR 250, subpart D, 1014- 0018.



### Subtotall 41 responses

Subsea Trees

(4) Y2 (5) Y2 1

i 827 

### NEW: Request remote location approval. I I request 2 1 submittal 

### 210 hours

246



# o

o

o


# o

246 hours



### 7

1 2

Y2 10 requests 5 1 831 

### NEW: Submit a repair/replacement plan to

I

- 

# 1monitor andtest.

_____-+-

________ 

### +-

_____ +-

________ ---I I 837(a) 

# jlNEW: Request approval to not shut-in a
2 1 submittal 2 

# L_______**subseawell~anem~genc~**____

### ~----~--~---~~-~~~~-~--~ : 837(b) 

### NEW: Prepare and submit for approval a

I plan to shut-in wells affected by a dropped

1

_________________ ollject.

-- Y2 2 approvals 1

2 2 4 verifications 2 1 approval 2 I 837(c)(2) II 

### NEW: Obtain approval to resume I**pr~ducti~!1~**P/!-_PSgL_s_e_n

__ s0-c-r_.

_____ j--

___ 

### -+

___ _ I 838(a); I 

### NEW: VerifY closure time ofUSV upon

I 839(a)(2); I request ofDistrict Manager.

i

# 838(c)~EW: Request approval to produce after

! .,- /
I

### i~ss ofcommunication; include alternate

i I valve closure table. 

### 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----- required/supporting information, for a $5,030 per submission x 1 

### = $5,030

I production safety system with> 125 $13,238 per offshore visit x 1 

### = $13,238

components. $6,884 per shipyard visit x 1 

### = $6,884 25

- 125 components. 13 10 130 applications

### 54423 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules


### I 

## I [2500:,"G

I 

### Submit modification to application for 

# r

pmduction safety system 

### whh > 

### 125 cOl11P.c>nents. 25 125 components.

< 25 components.

842(b) 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 842(c) NEW: Submit a certification letter that the mechanical and electrical systems were installed in accordance with approved designs. 842(d), (e); 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. 842(1) ] 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 ofthe facility.

Itlona ro uctlOn system Add' , 

### I P d S 

### R 851(a)(4) NEW: Request approval to use uncoded pressure and fired vessels beyond their 18 months ofcontinued use. I 

### 851(b); Maintain [most current] pressure-recorder

852(a)(3); information at location available to the 858(c); District Manager for as long as information 865(b); is valid. 851(c)(2) NEW: Request approval from District Manager for activation limits set less than 5 $1,218 per submission x 10= $12,180 I 

### $8,313 per offshore visit x 1 = $8,313 I $4,766 per, shipyard visit x 1 = $4,766 I I 

### 8 

### I 20 160 I 

### applications 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~** 

### 5 I 

### 329 1,645 

### I modifications I 

### $85 per submission x 329 = $27,965 I 

### 6

6 I I I I



### 6



### ;,s

;,s

Subtotal

eqmrements 2

23 I I 

# I 1 I 

### 32 192 certifications

32 letters 192

32 letters 208

32 records 16

1,426 9,485 I I I**_JesI~ons~s_._** 

### hours
-----_._---- ·-1 

### $343,794 non-hour cost burdens

1 request 2

615 records 14,145

10 requests 10 I I

### 54424 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules


### i ! 

### psi. 

### i 852(c)(l) I 

### NEW: 

### Request approval from District 1 10 requests 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 

### ofthe 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 ofall safety devices at location conveniently available to the District !--

____ +-M_anager for the life of_t_h_ec-f:a

__

c_i_lity-,,-,.

____ !--

___ ___+-----_+------I i 

### 858(b) NEW: 

### Request approval from District 1 Ii 

### 1 request 1
II I 

### Manager to use different procedure for gas- , 

### i well gas affected.

859(a)(2) Request approval for alternate firefighting system. 

# o Burden covered under 30 CFR 250, subpart A, 1014-0022.**~-----------------------** --+------------------------------------------------------------------------------------1--"-------------- '-.-------+---------------------1 

### 859(a)(3), Post diagram offirefighting system; furnish 5 38 postings 190 

### i (4) evidence firefighting system suitable for

II-I

-=-=-::-:::-:--

__

### +-:'o~p<e-=ra:o:t,=-io-cl1~i~**su!>geezi~!illl=a::c:t-=es=-:·_;:__--_+_:=____:_--J---:-__:-------+-------1** I 

### 859(b) NEW: 

### Request extension from District Burden covered under 30 0

I 

### I 

### Manager up to 7 days ofyour approved CFR 250, subpart A, 1014- departure to use chemicals. 0022.**---~~-~~c-~--~~~---+--c~-_,~~---___+--~---+** 

### 860(a); Request approval, including but not limited 22 31 requests 682 related to, submittal of justification and risk NTL(s) assessment, to use chemical only fire prevention and control system in lieu of a water system. 860(b)

I 

### 860(b) NEW: 

### Minor change(s) made after approval rec'd re 860(a)

- document change; maintain 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 I 

### rec'd re 860(a)

- submit new request

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. 'is 

### 10 minor changes

2 

### 1 major change

, 861(b) I NEW: 

### Submit foam concentrate samples 2 500 annually to manufacturer for testing. submittals 5

2



### 1,000

: 864 Maintain erosion control program records for 12 615 records 7,380

# ~______

# ~;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---~--+_~-----+_-~--~

, 867(a) NEW: 

### Request approval from District 6 1 request 6

1-1**~---c**___**!--M_a~er** 

### to install**te~rary** 

### qua_rt_er_s_.

__ ---+

____ ___+--------+------+ 

### I 

### 867(b) NEW: 

### Submit supporting 1 I request 1 information/documentation ifrequired 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 manager to use temporary equipment for 300 requests 300

### 54425 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**BILLING CODE 1505–01–C**

5. On page 52271, the table should read as follows:
**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;


### 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 Iflammable 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 Designand 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. Youmust 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, includingemergency 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:
**Item name 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. 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.


### 54427 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**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. (6) Steam generators operating at less than 15 psig ............................... 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. (7) Steam generators operating at 15 psig or greater .............................. (i) Must be equipped with a level safety low (LSL) sensor which willshut 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 as**  **sessment . . . Including . . .** 
(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 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) ............................... (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 toevacuation. State how you convey this information to your employees and contractor on the platform.


### 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 as**  **sessment . . . 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 inan 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:

**If your subsea gas** **lift system in troduces the**  **lift gas to the**

**. . . Then you must install a . . .** 

**Additional requirements API Spec 6A and API Spec**  **6AV1 (both incorporated by reference as specified in** **§ 250.198) gas-lift shut down valve (GLSDV), and** 

**. . . FSV on the** **gas-lift sup ply pipeline** 

**. . . PSHL on the** **gas-lift sup ply . . .**  **API Spec 6A and API Spec**  **6AV1 manual isolation**  **valve . . .** (1) Subsea

Pipelines,Pipeline Risers, or Manifoldsvia an External Gas Lift Pipeline. 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 downstream (out board) of the PSHL and abovethe waterline. This valve does not have to be actuated. (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-safeclose gas-lift isolation valve (GLIV) located at the point of intersection betweenthe 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).


### 54429 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**If your subsea gas** **lift system in troduces the**  **lift gas to the**

**. . . Then you must install a . . .** 

**Additional requirements API Spec 6A and API Spec**  **6AV1 (both incorporated by reference as specified in** **§ 250.198) gas-lift shut down valve (GLSDV), and** 

**. . . FSV on the** **gas-lift sup ply pipeline** 

**. . . PSHL on the** **gas-lift sup ply . . .**  **API Spec 6A and API Spec**  **6AV1 manual isolation**  **valve . . .** (2) Subsea

Well(s) through the Casing String via an External Gas Lift Pipeline. Locate the GLSDV within 10 feet of the first of access to the gas-lift riser or topsidesumbilical 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). 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 abovethe waterline. This valve does not have to be actuated. Install an actuated, fail-safe-closed GLIV onthe 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 anannulus master valve (AMV) or an annulus wing valve (AWV), one of these maybe designated as the GLIV. Consider installing the GLIV external to the subsea tree to facilitate repair and or replacement if necessary.

(3) Pipeline

Risers via a Gas-LiftLine Contained within the Pipeline Riser 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 ofthe TUTA if using an umbilical). 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-liftsystem 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 tubinghanger 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 platformprovide 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 thegas-lift line contained within the production riser. To facilitate the repair or replacement of the GLSDV or productionriser BSDV, you may install a manual isolation valve between the GLSDV and theAPI 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 tosuspend 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, pipeline riser, or manifold via an external gas lift pipeline. GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks.


### 54430 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**Type of gas lift system Valve**  **Allowable leakage rate**  **Testing frequency** GLIV .... N/A .................................................... Function tested quarterly, not to exceed 120 days. (ii) Gas Lifting a subsea well through the casing string

via an external gas lift pipeline. GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks.
GLIV .... 400 cc per minute of liquid or 15 scf per minute of gas. Function tested quarterly, not to exceed 120 days.(iii) Gas lifting the pipeline riser via a gas lift line contained within the pipeline riser. 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 valvesinstalled 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 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. 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 forboth 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.


### 54431 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules

**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 conductedby 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 thatcould 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 analogwith 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:
**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.


### 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. Ifmultiple 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**
**AGENCY :**  Centers for Disease Control and Prevention, HHS. **ACTION :**  Request for comment and notice of public meeting.
**SUMMARY :**  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 performancerequirements for the class of NIOSHcertified non-powered air-purifyingparticulate 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 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 AirPurifying 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