JUN 1 7 20Vi

June 16, 2014

Ms. Angie GobertChief, Pipeline UnitU.S. Department of the InteriorBureau of Safety and Environmental Enforcement1201 Elmwood Park BoulevardNew Orleans, Louisiana 70123-2394

Deborah R. MalbroughRegulatory Advisor Deepwater GoM Region

BP Exploration & Production Inc.200 Westlake Park Boulevard - 471F WL4 Houston, Texas 77079 Telephone: 713-323-2090 Email: [email protected]

JUN 1 7 20Vi

RE: Extension RequestsWaiver from CFR 250.1006 (b)(2) Flush & Fill 8” BLKG Pipeline and Waiver from CFR 250.1006 (b)(3) Decomission 8” BLKG Pipeline Pipeline Segment No. 13802, From MC 522 Sled SGi to MC 474 Na Kika Na Kika, Mississippi Canyon Block 474, Lease OCS-G 26259-Platform A

Ms. Gobert:

BP Exploration & Production Inc. (BP) by letter dated January 8, 2013 requested an extension of the waiver received from 30 CFR 250.1006(b)(2) flush and fill Pipeline (PL) Segment No. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. (SN) 13802 has been out-of-service since April 2010. BSEE subsequently stamp approved the flush and fill waiver on January 11, 2013 to allow for an in-line inspection (ILI) to be completed for re-validation of the pipeline. The flush and fill waiver extension was approved through June 30, 2014 (attached).

By letter dated June 12, 2013, BSEE denied BP’s request dated June 6, 2013, to utilize an ILI tool in lieu of a hydrotest to revalidate PL SN 13802 (attached). On September 25, 2013 BP met with the BSEE Pipeline Section to discuss PL SN 13802. By letter dated November 12, 2013 (attached), BP submitted an Alternate Compliance Request to BSEE to utilize a combination of inspection methods to reinstate PL SN 13802. The letter included information that BP presented in the September 2013 meeting and also detailed specific information/details requested by BSEE.

On March 20, 2014, BP met with the BSEE Pipeline Section and the Technical Assessment Section to discuss the request dated November 12, 2013. A revised letter dated March 19, 2014 (attached) was delivered to BSEE at the meeting. To date, BP has not received a response from BSEE.

As such, BP requests an additional extension of the waiver from flushing and filling PL SN 13802, until December 31, 2015. The extension will allow for a response from BSEE and affords BP sufficient time to respond, plan, and execute an activity that allows for the revalidation and reinstatement of PL SN 13802.

Additionally, BP requests approval to depart from the requirements of 30 CFR 250.1006 (b)(3), decommission the pipeline according to 30 CFR 250.1750-250.1754 for pipelines out of service for 5 or more years, until December 31, 2015 to allow for the revalidation and reinstatement of PL SN 13802 as detailed above.

If you have any questions please, contact the undersigned at (713) 323-2090, on cell (713) 557-9453 or deborah.malbrough(^bp.com.

Very truly yours,

Deborah R. Malbrough /Regulatory Advisor ^

attachments

In Reply Refer To: GE 1035A March 4^8, 2014

Formatted: Space Before: 0 pt, After: 0 pt

Ms. Deborah R. Malbrough BP Exploration & Production Inc.200 Westlake Park Blvd.446D WL4 Houston, Texas 77079

Dear Ms. Malbrough:

Reference is made to the following application that has been reviewed by this office:

Application Type: Departure Request Application Date: November 12, 2013

Work Description: Request an approval to utilize alternate compliance methods.-----------—detailed herein in lieu of the requirements of 30 CFR250.1003(b)(1).

Segment Size LengthNumber (inches) (feet) Service From To

13802 08 61,504 Bulk Gas SLED SG1 Platform AMississippi Canyon Mississippi Canyon Block 522 Block 474OCS-G08823 OCS-G26259

Our mfofmatkw records indicatees that this segment has been shut in since 04441April 1, 2010. Because BP I \ploration and Production. Inc. ( BP) did not appK lor and receive approval to maintain Ihc aforemeniioncd pipeline rigln-of-v\a\ urant in effect bevond ihe 90 days provided for hv a tempomn cessation of operati<ms. please he advised that pipeline Right- of-way No. OCS-G 24239 for Semnenl 13802 expired on June 30, 2010 as required in 30 CFR 250.1014.If this information is coffeet, the Righto»f-Way (K S-G 24239 for Segment 13802 has expired as of OX4M <2010.

Accordinaly. Thereh»re your this departure request is hereby denied.

Because the right-of-way has expired. BSEE would normally require decommissioning of the line. Howe\er. BSKE will approve the continued use of the line provided ii has been inteurity tested in a manner deemed sufficient for reinstatement.

Please provide RSHE with a proposal outlinitm tcsiiiprocedures that will be used and which

addresses the concerns detailed in this letter.

You may however;hy4f^afbtws-<ava-tKa'-n->a]-basls--t>tt{T-rs4ftstea4-tfsed-a;f ai> oecasioival |aig loop.

Backtiround

On June 6. 2013 BP requested a departure from 30 CTR 250.10()3(b)( I). which states"Pipelines shall be pressure tested with water at a stabilized pressure ofat least 1.25 times theMAOP for at least 8 hours when installed, relocated, uprated or reactivated, after beinu out-of-service for more t han a year." In lieu ofa hydrotesi. I *P proposed utilizi ng the results of an In- Line Inspection (1L1) of the pipeline. This request was denied because the line had been out ofservice for more than one year.

Formatted: Space After: 12 pt

| Formatted: Font: Bold

[ Formatted: Normal, Line spacing: single

As per In ow^a meeting between representatives of BP and BSEE Regional Field Operations held on March 20, 2014. here at the BSEE Elmwood office, vr>u BP stated several difficulties in normal testing to reactivate the pipeline. One of the wain issues was using water to reactivate

pressure tested with water at a stab-feetf pressin-e-ol'at-least- E25 times-the-K iKinns when i nst a 11 ed. - re k >e ated. ti prated or reaeti vatecLarftef-heing out-trlYervece for rrurre-tltan

a-year.”- Possible hydrate formation and extended dr\ ini’ time wereas the stated problems with using water as the testing fluid. A4sq-vou-BP also stated that testing with nitrogen would be very difficult with extensive operational problems.

BP personnel stated that they would like to keep the MAOP of this seument to its present 7554psi. Al presenl there are no wells or pipeline input sources lhai require this hieh MAOP.BP also stated that possible future wells mav require <> MAOP of 7554 psi.

BP personnel cfkl recommended testing the pipeline to i£7Y 1650 psi with unprocessed natural gas and running a caliper device (pig) as an equivalent testing procedure, to the normal CFR testing procedure. This pig, known as a Mechanical Feeler Defect tool, would check for pitting and give a snapshot of any internal C02 damage.

BSEE C oncerns Formatted: Font: Bold

Without a full pressure test on ihe pipeline. BSEE cannot approve reinstating an MAOP of 7554psiu because the line has been out of service for four years. The use of the MechanicalPeeler Defect tool cannot substitute for a full hvdrotest because it will only provide information about pittinu. not cracks or other defects in the line.

BSEE also cannot approve pressure testing at 1.25 x 7554psit’ with aas because it is toodanucrous. Testimi at such hiah pressures with aas presents too ureat a risk of fire or explosion.

Additionally, it is unlikely that BSEE will approve a proposal that includes tcstiim at 1650psiPressure teslinu at such a low pressure will not reveal integrity information about the subseasegments of the pipeline because the pressure in the line will be insufficient to overcome thehydrostatic head.

Possible Options Formatted: Font: Bold

BSEE enuineers have developed a series of testini’ procedures that may receive approval:

I. If BP wishes to reinstate the riuht-of-wav and use the line for transportinu uas with an * Formatted: indent: left: 0.25

MAOP of 7554psiu the line must undereo a full hvdrotest at 1.25 \ MAOP tisinu water or nitrogen.

2. If BP wishes to reinstate the right-ol-v\a\ and use the line lor transportinu uas with a reduced M AOP of 2.300psiu, the current SUP of wells in the Na Kika System, the linemust be pressure tested at 1.25 x MAOP, but processed uas mav be used. Additionally.the integrity of the line shall he tested using an IEI tool.

3. If BP wishes to use the line for pigging purposes only. BP mav apply for an accessorydesignation for this pipeline. The Iine must be pressure tested at 1.25 \ MAOP andprocessed gas mav be used.

Please note that am proposal that involves lowering the MAOP of the line below the MAOP ofthe other pipelines in the system must also include procedures to protect the line fromoverpressure.

BB{>ersoime1statecE4ltat they would like to keeplhe-YlAOP of th4s-segment to its present7-5A4f>si. At present there are no wells or pipeline input sources that require this high MAOP.BR also stated that possible tutore-welk may retjuoe-A MAOP of 7554 psi.

Sincerely,

For: — Nick Wetzel Regional Supervisor Regional Field Operations

bee: 1502-01 Segment No. 13802 with application (GE 1035A)

Deborah R. MalbroughRegulatory Advisor Gulf of Mexico Region

BP Exploration & Production Inc.200 Westlake Park Boulevard - 471F WL4 Houston, Texas 77079 Telephone: 713-323-2090 Email: [email protected]

November 12, 2013

Mr. Nick WetzelRegional Supervisor, Regional Field OperationsU.S. Department of the InteriorBureau of Safety and Environmental Enforcement1201 Elmwood Park BoulevardNew Orleans, Louisiana 70123-2394

Reference: Pipeline Segment No. 13802 - 8-inch Bulk Gas Alternate Compliance Request Na Kika Semi-Submersible PlatformMississippi Canyon Area Block 474, RUE OCS-G 23624 Platform A

Attn: Ms. Angie GobertPipeline Section Chief

Gentlemen:

BP Exploration & Production Inc. (BP) requests approval to utilize alternate compliance methods detailed herein in lieu of the requirements of 30 CFR 250.1003(b)(1). Pipeline Segment Number (PL SN) 13802 is an 8-inch Bulk Gas pipeline that originates at Sled SG-i in MC 522 and terminates at the Na Kika Semi Submersible Platform, MC 474, RUE OCS-G 23624, Platform “A”. PL SN 13802 has been out of service (OOS) since April 2010.

BP met with the BSEE Region Pipeline Section (Ms. Angie Gobert and Messrs. Shrestha, Patton and Hunter) on September 25, 2013 at which time BP presented information in support of an alternate compliance request.

Alternate Compliance Request:

BP requests approval to utilize a combination of inspection methods to reinstate PL SN 13802. First, BP plans to perform targeted inspections in the high consequence areas to confirm the external conditions of the Riser Hull Piping and through the Splash Zone up to EL+30’. Second, BP plans to perform an In-line Inspection (ILI) utilizing a Mechanical Feeler Defect (MFD) tool (details attached) to internally inspect the pipeline for metal loss using produced gas as the propelling medium. Third, and following the ILI, BP plans to perform a leak test of the PL using produced gas to 1650 psig (topside) which equates to a subsea test pressure of 1875 psia which is 1.25 x 1500 psia (normal operating pressure Subsea). As part of the leak test BP plans to utilize an remotely operated vehicle (ROY) to visually confirm zero leaks in the sled piping and valves.

The proposed alternate compliance methods detailed above are considered equal to or better than a hydrotest in confirming the integrity of Pipeline Segment No. 13802 and would be performed prior to placing the PL back into service.

PL Segment No. 13802Alternate Compliance RequestNovember 12, 2013Page 2

PLSN 13802 History:

A hydrotest of PL SN 13802 was performed (MAOP of 7554 psig x 1.25 for 8 hours) in October 2003 after installation and prior to placing into service as required by regulation. During the hydrotest, a remotely operated vehicle (ROV) was utilized to visually confirm zero leaks in the sled piping and subsea valves. PL SN 13802 was subsequently placed into service as part of Na Kika’s South Gas Loop (SGL). General visual inspections have been performed since installation to confirm the external conditions of the pipeline, and cathodic potential surveys have been performed to confirm cathodic protection.

PL SN 13802, OOS since April 2010, was subsequently filled with nitrogen in July 2011 for long-term preservation purposes. By letter dated December 16, 2011, BP submitted a request to depart from the flush and fill requirements of 30 CFR 250.1006(b)(2) since the flowline was in a stable condition and flushing and filling with water would not assist in maintaining flowline integrity. The letter stated that PL SN 13802 may be revalidated in the future if tie-in needs arose; the letter further stated that BP was planning an in-line inspection (ILI) of the SGL in 2013. BSEE stamp approved the departure on July 17, 2012.

By letter dated January 8, 2013, BP updated BSEE on the ILI of PL SN 13802, planned for February 2014, and requested an extension of the flush and fill departure to June 30, 2014 to allow for the ILI and subsequent results to be received and reviewed. On January 11, 2013, BSEE stamp approved the extension until June 30, 2014. For note, the PL pressure has been monitored and remains stable at 20 psig.

Na Kika South Gas Loop Confumration

The Na Kika SGL consists of two fields, East Anstey and Fourier. There are currently three (3) gas wells tied-in to the loop; wells EA-2, F2 and F6. The SGL is comprised of four (4) primary pipeline segments and several associated well/flowline jumpers. The primary' PL segments are SN 13802 (8" BLKG from Sled SGi to MC 474A; Fourier side), SN 13797 (8” BLKG from Sled SG2 to Sled SG3), SN 13798 (8" BLKG from Sled SG4 to Sled SG5) and SN 13786 (8" BLKG from SG6 to MC 474A; East Anstey side). See attached exhibits SGL Field Layout and SGL Flowline Loop Details.

The SGL is configured such that hydrocarbons can be flowed through either the Fourier side or the East Anstey side. Since PL SN 13802 (Fourier side) was placed OOS in 2010, all production currently flows up the East Anstey side of the loop.

Reinstating PL SN 13802 would maximize future opportunities for the flow loop and would enhance inspection alternatives which includes, but is not limited to, ILL

Supportimi Information:

BP offers the following information in support of the alternate compliance request above:

• Why performing a hydrostatic test after a gas pipeline has been in service is different than a commissioning hydrostatic test?

Introduction of water to a gas system can result in gas hydrate formation. Gas hydrates are 'ice- like' crystals composed of gas and water that form more readily under high pressure and low temperature. These conditions are typical of the deep-sea environments to which the Na Kika South


Gas flowloop is subject to. The hydrate crystals agglomerate to form large solid plugs that can block pipelines.

During the initial commissioning of the system, hydrate formation is not a concern because hydrocarbon gas has not yet been introduced and the system is dried prior to introduction of the

gas.

Additionally, during initial commissioning the hub (platform) can often easily accommodate the added equipment required to dry the line following a hydrostatic test, because not all of the topside equipment has been installed.

• Why are the risks associated with a hydrostatic test greater than an Inline Inspection tool run?

In addition to the risk of hydrate formation, a hydrostatic test will require simultaneous operations between the Na Kika hub and a marine vessel for an extended period of time to dry the line. There is insufficient free deck space on Na Kika to accommodate the Nitrogen Generation Spread required to facilitate drying of the line; estimated duration for this activity is between 21 and 28 days. This method will also require high pressure temporary connections between the hub and the marine vessel. The identified control of work risks associated with this activity are significant, in particular vessel collision with the Na Kika hub and/or risers.

The possibility of hydrate formation end the control of work risks associated with extended use of a third-party vessel can be eliminated through implementation of an ILI tool run.

• Why is ILI considered a suitable alternative to hydrostatic test for re-instatement of this specific pipeline?

Inspection by ILI provides maximum inspection coverage of the pipeline, which includes inaccessible areas. Also, ILI provides quantitative data as to the physical condition of the pipeline and does not interfere with the operating envelopes of the pipeline equipment.

Hydrotest is only valid at the point in time which it is performed and does not provide any quantitative data as to the physical condition of the pipeline (i.e. does not provides indication of corrosion issues).

Data gathered from ILI, in combination with targeted inspection and a leak test, provides confirmation of integrity equal to or better than a hydrotest.

• Summary of future inspection plans for the system:

BP's Pipeline Integrity Management Systems' processes are followed to identify the frequency and type of activities required to maintain safe and continuous operation of the system. These activities can include:

• Above water visual inspection and non-destructive examination• Splash zone visual inspection

• ER probe/corrosion coupon monitoring• Maintenance pigging• Inline inspections

• ROV visual inspections

• ROV cathodic protection surveys

The type of activity and its associated frequency is reviewed annually. Currently, the Na Kika South Gas loop is scheduled for inline inspection, which includes visual inspections, in 2014.

Please advise if any additional information is required for approval of the alternate compliance request for PL SN 13802 (utilization of a combination of inspection methods to reinstate the subject pipeline).

If you have any questions please, contact the undersigned at (713) 323-2090, on cell (713) 557_9453 or deborah.malbrough(5)bp.com.


Qi rtr'nt’ol 1 r

Deborah Malbrough Regulatory Advisor

MFD Tool (PFT -3600) Specifications Na Kika South Gas Loop (NKSG) Drawing SGL Flowline Loop Details Na Kika SGL System Data

Attachments:

Deborah R. MalbroughRegulatory Advisor Gulf of Mexico Region

BP Exploration & Production Inc.200 Westlake Park Boulevard - 471F WL4 Houston, Texas 77079 Telephone: 713-323-2090 Email: deborah [email protected]

November 12, 2013 REVISED 3/19/2014

Mr. Nick WetzelRegional Supervisor, Regional Field OperationsU.S. Department of the InteriorBureau of Safety and Environmental Enforcement1201 Elmwood Park BoulevardNew Orleans, Louisiana 70123-2394

Reference: Pipeline Segment No. 13802 - 8-inch Bulk Gas Alternate Compliance Request Na Kika Semi-Submersible PlatformMississippi Canyon Area Block 474, RUE OCS-G 23624 Platform A

Attn: Ms. Angie GobertPipeline Section Chief

Gentlemen:

BP Exploration & Production Inc. (BP) requests approval to utilize alternate compliance methods detailed herein in lieu of the requirements of 30 CFR 250.1003(b)(1). Pipeline Segment Number (PL SN) 13802 is an 8-inch Bulk Gas pipeline that originates at Sled SG-i in MC 522 and terminates at the Na Kika Semi Submersible Platform, MC 474, RUE OCS-G 23624, Platform “A”. PL SN 13802 has been out of service (OOS) since April 2010.

BP met with the BSEE Region Pipeline Section (Ms. Angie Gobert and Messrs. Shrestha, Patton and Hunter) on September 25, 2013 at which time BP presented information in support of an alternate compliance request.

Alternate Compliance Request:

BP requests approval to utilize a combination of inspection methods to reinstate PL SN 13802. First, BP plans to perform targeted inspections in the high consequence areas to confirm the external conditions of the Riser Hull Piping and through the Splash Zone up to EL+30’. Second, BP plans to perform an In-line Inspection (ILI) utilizing a Mechanical Feeler Defect (MFD) tool (details attached) to internally inspect the pipeline for metal loss using produced gas as the propelling medium. Third, and following the ILI, BP plans to perform a leak test of the PL using produced gas to 1650 psig (topside) which equates to a subsea test pressure of 1875 psia which is -1.25 x 1500 psia (normal operating pressure Subsea). As part of the leak test BP plans to utilize a remotely operated vehicle (ROV) to visually confirm zero leaks in the piping.

The proposed alternate compliance methods detailed above are considered equal to or better than a hydrotest in confirming the integrity of Pipeline Segment No. 13802 and would be performed prior to placing the PL back into service.

t’L Segment No. 13802Alternate Compliance RequestNovember 12, 2013 - REVISED 3/19/14Page 2

PL SN 13802 History:

A hydrotest of PL SN 13802 was performed (MAOP of 7554 psig x 1.25 for 8 hours) in October 2003 after installation and prior to placing into service as required by regulation. During the hydrotest, a remotely operated vehicle (ROV) was utilized to visually confirm zero leaks in the sled piping and subsea valves. PL SN 13802 was subsequently placed into service as part of Na Kika’s South Gas Loop (SGL). General visual inspections have been performed since installation to confirm the external conditions of the pipeline, and cathodic potential surveys have been performed to confirm cathodic protection.

PL SN 13802, OOS since April 2010, was subsequently filled with nitrogen in July 2011 for long-term preservation purposes. By letter dated December 16, 2011, BP submitted a request to depart from the flush and fill requirements of 30 CFR 250.1006(b)(2) since the flowline was in a stable condition and flushing and filling with water would not assist in maintaining flowline integrity. The letter stated that PL SN 13802 may be revalidated in the future if tie-in needs arose; the letter further stated that BP was planning an in-line inspection (ILI) of the SGL in 2013. BSEE stamp approved the departure on July 17, 2012.

By letter dated January 8, 2013, BP updated BSEE on the ILI of PL SN 13802, planned for February 2014, and requested an extension of the flush and fill departure to June 30, 2014 to allow for the ILI and subsequent results to be received and reviewed. On January 11, 2013, BSEE stamp approved the extension until June 30, 2014. For note, the PL pressure has been monitored and remains stable at 20 psig.

Na Kika South Gas Loop Configuration

The Na Kika SGL consists of two fields, East Anstey and Fourier. There are currently three (3) gas wells tied-in to the loop; wells EA-2, F2 and F6. The SGL is comprised of four (4) primary pipeline segments and several associated well/flowline jumpers. The primary PL segments are SN 13802 (8” BLKG from Sled SGi to MC 474A; Fourier side), SN 13797 (8" BLKG from Sled SG2 to Sled SG3), SN 13798 (8” BLKG from Sled SG4 to Sled SG5) and SN 13786 (8” BLKG from SG6 to MC 474A; East Anstey side). See attached exhibits SGL Field Layout and SGL Flowline Loop Details.

The SGL is configured such that hydrocarbons can be flowed through either the Fourier side or the East Anstey side. Since PL SN 13802 (Fourier side) was placed OOS in 2010, all production currently flows up the East Anstey side of the loop.

Reinstating PL SN 13802 would maximize future opportunities for the flow loop and would enhance inspection alternatives which includes, but is not limited to, ILL

Supporting Information:

BP offers the following information in support of the alternate compliance request above:

• Why performing a hydrostatic test after a gas pipeline has been in service is different than a commissioning hydrostatic test?

Introduction of water to a gos system can result in gas hydrate formation. Gas hydrates are 'ice- like' crystals composed of gas and water that form more readily under high pressure and low temperature. These conditions are typical of the deep-sea environments to which the Na Kika South

'PL Segment No. 13802Alternate Compliance RequestNovember 12, 2013 - REVISED 3/19/14Page 3

Gas flowloop is subject to. The hydrate crystals agglomerate to form large solid plugs that can

block pipelines.

During the initial commissioning of the system, hydrate formation is not a concern because hydrocarbon gas has not yet been introduced and the system is dried prior to introduction of the

gas.

Additionally, during initial commissioning the hub (platform) can often easily accommodate the added equipment required to dry the line following a hydrostatic test, because not all of the topside equipment has been installed.

• Why are the risks associated with a hydrostatic test greater than an Inline Inspection tool run?

In addition to the risk of hydrate formation, a hydrostatic test will require simultaneous operations between the Na Kika hub and a marine vessel for an extended period of time to dry the line. There is insufficient free deck space on Na Kika to accommodate the Nitrogen Generation Spread required to facilitate drying of the line; estimated duration for this activity is between 21 and 28 days. This method will also require high pressure temporary connections between the hub and the marine vessel. The identified control of work risks associated with this activity are significant, in particular vessel collision with the Na Kika hub and/or risers.

The possibility of hydrate formation and the control of work risks associated with extended use of a third-party vessel can be eliminated through implementation of an ILI tool run.

• Why is ILI considered a suitable alternative to hydrostatic test for re-instatement of this specific pipeline?

Inspection by ILI provides maximum inspection coverage of the pipeline, which includes inaccessible areas. Also, ILI provides quantitative data as to the physical condition of the pipeline and does not interfere with the operating envelopes of the pipeline equipment.

Hydrotest is only valid at the point in time which it is performed and does not provide any quantitative data as to the physical condition of the pipeline (i.e. does not provides indication of corrosion issues).

Data gathered from ILI, in combination with targeted inspection and a leak test, provides confirmation of integrity equal to or better than a hydrotest.

• Summary of future inspection plans for the system:

BP's Pipeline Integrity Management Systems' processes are followed to identify the frequency and type of activities required to maintain safe and continuous operation of the system. These activities can include:

• Above water visual inspection and non-destructive examination

• Splash zone visual inspection

• ER probe/corrosion coupon monitoring

• Maintenance pigging• Inline inspections

Segment No. 13802Alternate Compliance RequestNovember 12, 2013 - REVISED 3/19/14Page 4

• ROV visual inspections

• ROV cathodic protection surveys

The type of activity and its associated frequency is reviewed annually. Currently, the Na Kika South Gas loop is scheduled for inline inspection, which includes visual inspections, in 2014.

Please advise if any additional information is required for approval of the alternate compliance request for PL SN 13802 (utilization of a combination of inspection methods to reinstate the subjectpipeline).

If you have any questions please, contact the undersigned at (713) 323-2090, on cell (713) 557-9453 or [email protected].

Sincorclv.

Deborah Malbrough Regulator)' Advisor

MFD Tool (PFT -3600) Specifications Na Kika South Gas Loop (NKSG) Drawing SGL Flowline Loop Details Na Kika SGL System Data

Attachments:

8” HWTPFT 36 III8” Porcupine Pig tool

TECHNICAL SPECIFICATIONS

L?V\PtWAYNTERN ATIQN AL

MIH—General Data Metric Imperial

Number of sections 5

Length 1850mm 6'-r

A - 318 mm A-12.5"

B - 318 mm B- 12.5"

Dimensions per sections (excluding jo nts length) C - 208 mm C - 8.2“

D - 208 mm D - 8.2“

E - 294 mm E - 11.6“

Weight 38 kg 84 lbs

Operational Conditions Metric Imperial

Maximum temperature11’ 60°C 140°F

Maximum pressure 352 Bars 5000 PSI

Minimum operational pressure for gas pipelines 10 Bars 145 PSI

Minimum bend radius 3 D

Maximum speed1*’ 2 m/s 6 ft/s

Optimum speed12’ 0,7 -1 m/s 2 - 3 ft/s

Minimum bore127 mm

straight pipe5”

straight pipe

Autonomy with full power consumption'*' 30 h

Data acquisition autonomy'*’ 24 h without stand-by

Sensor Data Metric Imperial

Number of feeler sensors

Nominal circumferential spacing of sensors

Sensor sampling rate

96

7,1 mm 0.28"

1000 Hz

WWW pipitway cnmr>A^ i n

PFT 36iill8” Porcupine Pig tool


8” HWT

Measurement characteristics Metric Imperial

Sensor radial movement A/D resolution 11 0.01 mm less than 0 001"

Sensor radial step movement measurement precision12’ 0.2 mm 0.008"

Minimum pit axial length for full 1 mm depth measurement*” 3 mm 0.118"

Minimum pit axial length for full 2 mm depth measurement'” 7 mm 0.276"

Minimum pit axial length for full 10 mm depth measurement'” 20 mm 0.787"

Odometer accuracy ± 0.3%

Feature axial position accuracy referred to near circumferential weld ± 0 1 m 3937"

Circumferential position accuracy ±10°

Automated analysis characteristics Metric Imperial

Minimum defect depth at pipe wall for 90% POD ±1 mm 0039"

Minimum defect depth at circumferential welds for 90% POD ±2 mm 0.079"

Defect depth accuracy with 80% reliability at pipe wall ±1 mm 0.039"

Defect depth accuracy with 80% reliability at circumferential welds ±1 mm 0039"

Defect length accuracy with 80% reliability at pipe wall ±5 mm 0.197”

Defect length accuracy with 80% reliability at circumferential welds ±10 mm 0394"

Defect width accuracy with 80% reliability ±6 mm 0.236"

www pipirwiy com

8” Porcupine Pig tool


PFT 360 - 8” HWT

Analysis methodology

Data analysis is a combination of manual and automatic techniques, involving both batch software with sophisticated mathematical algorithms and interactive graphical visualization software

In the first place anomalies are automatically detected on a per channel basis Those are called channel anomalies, and can be as short as 5 mm (0 19") or as long as 1 m (39 4") Their actual depth profile may be recorded apart for further processing

Pipeline dents and ovalities are detected to validate the metal loss automatic analysis. This is required because the algorithms can compensate for dents and ovalities up to certain levels. Feeler sensor indications in regions with more severe deformations have to be analyzed manually, with detailed manual feature dimensioning or general semi-quantitative evaluation

Then channel anomalies are grouped together to form anomalies. An anomaly marks a rectangular pipe area delimited by contiguous channel anomalies, both in the axial and circumferential directions Due to the very inspection technique nature, an anomaly may be really big if compared with typical MFL inspection indications Its profile may be composed from the profile of its individual channel anomalies and recorded apart, for further processing

Anomalies are then grouped to form clusters, with criteria such as that established by POF (Pipeline Operators Forum)

Anomaly distribution is analyzed with the help of several statistical charts Clusters are analyzed with a Level 1 criteria such as B31G or a Level 2 criteria such as RSTRENG Effective Area (this considers the whole detail of defect profile and is still under development, scheduled for third quarter of 2009)

Incrustations are also detected on a per channel basis and grouped the same way as regular anomalies, but they form a distinct kind of feature They are also analyzed with the help of statistical charts, but are not clustered.

Signals at selected regions may be manually analyzed to get the most from the tool. However, this should be reserved for really special cases, to keep the required work at feasible levels

www pipitway como/o

WELL F-2 SCM& CHOKE

Na Kika 8inch South Gas Loop Layout

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BP Exploration & Production Inc.200 Westlake Park. Boulevard - 471F Wl.4 Houston, Texas 77079 Telephone: 713-323-2090 f mail [email protected]

June 16, 2014

Ms. Angie GobeitChief, Pipeline UnitU.S. Department of the InteriorBureau of Safety and Environmental Enforcement1201 Elmwood Park BoulevardNew Orleans, Louisiana 70123-2394

RE: Extension RequestsWaiver from CFR 250.1006 (b)(2) Flush & Fill 8” BLKG Pipeline and Waiver from CFR 250.1006 (b)(3) Dceomission 8” BLKG Pipeline Pipeline Segment No. 13802, From MC 522 Sled SGi to MC 474 Na Kika Na Kika, Mississippi Canyon Block 474, Lease OCS-G 26259-Platform A

Ms. Gobert:

Deborah R. MalbroughRegulatoty AdvisorDeepwater GoM Region

BP Exploration & Production Inc. (BP) by letter dated January 8, 2013 requested an extension of the waiver received from 30 CFR 250.1006(b)(2) flush and fill Pipeline (PL) Segment No. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. (SN) 13802 has been out-of-service since April 2010. BSEE subsequently stamp approved the flush and fill waiver on January 11, 2013 to allow for an in-line inspection (ILI) to be completed for re-validation of the pipeline. The flush and fill waiver extension was approved through June 30, 2014 (attached).

By letter dated June 12, 2013, BSEE denied HP’s request dated June 6, 2013, to utilize an ILI tool in lieu of a hydrotest to revalidate PL SN 13802 (attached). On September 25, 2013 BP met with the BSEE Pipeline Section to discuss PL SN 13802. By letter dated November 12, 2013 (attached), BP submitted an Alternate Compliance Request to BSEE to utilize a combination of inspection methods to reinstate PL SN 13802. The letter included information that BP presented in the September 201.3 meeting and also detailed specific information/details requested by BSEE.

On March 20, 2014. BP met with the BSEE Pipeline Section and the Technical Assessment Section to discuss the request dated November 12, 2013. A revised letter dated March 19. 2014 (attached) was delivered to BSEE at the meeting. To date, BP has not received a response from BSEE.

As such. BP requests an additional extension <>!' the waiver from flushing and filling PL SN 13802, until December 31, 2015. The extension will allow for a response from BSEE and affords BP sufficient time to respond, plan, and execute an activity that allows for the revalidation and reinstatement of PL SN 13802.

Additionally, BP requests approval to depart from the requirements of 30 CFR 250.1006 (b)(3), decommission the pipeline according to 30 CFR 250.1750-250.1754 for pipelines out of sendee for 5 or more years, until December 31. 2015 to allow for the revalidation and reinstatement of PL SN 13802 as detailed above.

If you have any questions please, contact the undersigned at (713) 323-2090, on cell (713) 557-9453 ofdeborah-malbroughfa bp.com.

Very truly yours,

Deborah R. Malbrough Regulatory Advisor

attachments

Deborah R. MalbroughRegulatory Advisor

BP Exploration & Production Inc.200 Westlake Park Blvd., 471F WL4 Houston, Texas 77079 Telephone: 713-909-8508 Email: [email protected]

December 15, 2015

Ms. Angie Gobert Pipeline Unit ChiefBureau of Safety and Environmental Enforcement 1201 Elmwood Park Boulevard, GE1035A New Orleans, Louisiana 70123-2394

RE: Extension / Waiver Requests - Pipeline Segment No. 13802Na Kika Semi-Submersible PlatformMississippi Canyon Block 474, RUE OCS-G 23624 Platform A

Sureou of Safsiy otu! [iwironmantal Enforc*! (sbEE)

R F C E 1 V E DDEC 17 2015

Office of field Operations Pipeline Section

Ms. Gobert:

BP Exploration & Production Ine. (BP) by letter dated January 8, 2013 requested an extension of the waiver received from 30 CER 250.1006(b)(2) flush and fill Pipeline (PL) Segment No. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. (SN) 13802 has been out-ofservice (OOS) since April 2010. BSEE subsequently stamp approved the flush and fill waiver on January 11, 2013. The flush and fill waiver extension was approved through June 30, 2014 (attached).

By letter dated June 16, 2014, BP requested an additional extension of the waiver received from 30 CER 250.1006(b)(2). The flush and fill waiver extension was requested through December 31, 2015 (attached). Additionally, BP requested approval to depart from the requirements of 30 CER 250.1006 (b)(3), decommission the pipeline according to 30 CER 250.1750-250.1754 for pipelines out of service for 5 or more years, until December 31, 2015. To date, a response from the BSEE PL Section has not been received on either request.

BP has since decided not to revalidate and reinstate PL SN 13802. The pipeline remains out-of-service (OOS) and filled with nitrogen for long-term preservation purposes. The PL is isolated from the facility with a blind flange on topsides and an ROV installed lock-out on the subsea SGi sled isolates it from the flowloop.

PL SN 13802 is part of Na Kika’s South Gas Loop (SGL). The Na Kika SGL served two fields, East Anstey and Fourier. The East Anstey wells have been abandoned, therefore there are currently only two (2) Fourier gas wells tied-in to the loop; wells F2 and F6. The SGL is comprised of four (4) primary pipeline segments and several associated well/flowline jumpers. The primary PL segments are SN 13802 (8” BLKG from Sled SGi to MC 474A; Fourier side), SN 13797 (8” BLKG from Sled SG2 to Sled SG3), SN 13798 (8” BLKG from Sled SG4 to Sled SG5) and SN 13786 (8” BLKG from SG6 to MC 474A; East Anstey side). See attached SGL Flowloop details.

The SGL is configured such that hydrocarbons can be flowed through either the Fourier side or the East Anstey side. Since PL SN 13802 (Fourier side) was placed OOS, all production flows up the East Anstey side of the loop.

Since PL SN 13802 is part of an active flowloop, BP requests an extension of the waiver from 30 CFR 250.1006(b)(2) until the Na Kika Field “end of life”. The extension will allow for the pipeline to remain filled with nitrogen until it will be removed/abandoned as pail of the flowloop abandonment when the Na Kika facility is removed from the OCS.

Additionally, BP requests approval to depart from the requirements of 30 CFR 250.1006 (b)(3) until the Na Kika Field “end of life”. The extension will allow for the pipeline to remain in place until it is removed/abandoned as part of the flowloop abandonment when the Na Kika facility is removed from the OCS.


Very truly yours,


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BP Exploration & Production Inc.200 Westlake Park Blvd., 471F WL4 Houston, Texas 77079Telephone: 713-909-8508Lmail: [email protected]

October 24, 2016

Ms. Angie Gobert Pipeline Unit Chief

Bureau of Safety and Environmental Enforcement

1201 Elmwood Park Boulevard, GE103!5A New Orleans, Louisiana 70123-2394

Attn: Mr. Brad Hunter

RE: Additional Information RrquestExtension / Waiver Requests - Pipeline Segment No. 13802Na Kika Semi-Submersible Platform

Mississippi Canyon Block 474, RUE OCS-G 23624 Platform A

Mr. Hunter:

BP Exploration & Production Inc. (BP) by letter dated December 15, 2015 (attached) requested an

extension of the waiver from 30 CFR 250.1006(b)(2) allowing for the pipeline to remain filled with nitrogen and also to depart from the requirements of 30 CFR 250.1006 (b)(3) allowing the pipeline

to remain as-is and in-place until it is removed/abandoned as part of the flowloop abandonment when the Na Kika facility is removed from the OCS (Na Kika Field "end-of-life").

PL SN 13802 is a primary segment of Na Kika's South Gas Loop (SGL), the Fourier side of an active

flowloop. The SGL is configured such that hydrocarbons can be flowed through either the Fourier side or the East Anstey side. Since PL SN 13802 (Fourier side) was placed OOS, all production

flows up the East Anstey side of the loop.

BSEE requested further justification for this request. Leaving the PL in place until field end-of-life maintains the flow loop configuration which supports the following:

1. Maintain the flow loop configuration to enable piggability for integrity management

purposes, if required.

2. Maintain the flow loop configuration to allow for remediation of flow assurance issues (such as hydrates), if required.

3. Maintain the flow loop configuration for decommissioning activities at the end of life to facilitate inventory displacement/flowline cleaning.

BSEE approval of this request as outlined above and as submitted by letter dated 12/15/2015 is

appreciated. For additional information, please contact the undersigned at (713) 557-9453 or [email protected].

\/fm/ trul\/ x/mirR

IRegulatory Advisor


BP Exploration & Production Inc.200 Westlake Park Blvd., 471F WI.4 Houston, Texas 77079 Telephone: 713-909-8508 Email: [email protected]

December 15, 2015

Ms. Angie Gobert Pipeline Unit ChiefBureau of Safety and Environmental Enforcement 1201 Elmwood Park Boulevard, GE1035A New Orleans, Louisiana 70123-239/]

RE: Extension / Waiver Requests - Pipeline Segment No. 13802Na Kika Semi-Submersible PlatformMississippi Canyon Block 474, RUE OCS-G 23624 Platform A

Ms. Gobert:

BP Exploration & Production Inc. (BP) by letter dated January 8, 2013 requested an extension of the waiver received from 30 CFR 250.1006(b)(2) flush and fill Pipeline (PL) Segment No. 13802 with inhibited seawater when the pipeline is out of sendee for more than one year but less than 5 years. Segment No. (SN) 13802 has been out-ofservice (OOS) since April 2010. BSEE subsequently stamp approved the flush and fill waiver on January 11, 2013. The flush and fill waiver extension was approved through June 30, 2014 (attached).

By letter dated June 16, 2014, BP requested an additional extension of the waiver received from 30 CFR 250.1006(b)(2). The flush and fill waiver extension was requested through December 31, 2015 (attached). Additionally, BP requested approval to depart from the requirements of 30 CFR 250.1006 (b)(3), decommission the pipeline according to 30 CFR 250.1750-250.1754 for pipelines out of service for 5 or more years, until December 31, 2015. To date, a response from the BSEE PL Section has not been received on either request.

BP has since decided not to revalidate and reinstate PL SN 13802. The pipeline remains out-of-service (OOS) and filled writh nitrogen for long-Lerm preservatior purposes. The PL is isolated from the facility with a blind flange on topsides and an ROV installed lock-out on the subsea SGi sled isolates it from the flowloop.

PL SN 13802 is part of Na Kika’s South Gas Loop (SGL). The Na Kika SGL served two fields, East Anstey and Fourier. The East Anstey wells have been abandoned, therefore there, are currently only two (2) Fourier gas wells tied-in to the loop; wells F2 and F6. The SGL is comprised of four (4) primary pipeline segments and several associated well/flowline jumpers. The primaiy PL segments are SN 13802 (8” BLKG from Sled SGi to MC 474A; Fourier side), SN 13797 (8” BLKG from Sled SG2 to Sled SG3), SN 13798 (8” BLKG from Sled SG4 to Sled SG5) and SN 13786 (8” BLKG from SG6 to MC 474A; East Anstey side). See attached SGL Flowloop details.

The SGL is configured such that hydrocarbons can be flowed through either the Fourier side or the East Anstey side. Since PL SN 13802 (Fourier side) was placed OOS, all production flows up the East Anstey side of the loop.

Since PL SN 13802 is part of an active flowloop, BP requests an extension of the waiver from 30 CFR 250.1006(b)(2) until the Na Kika Field “end of life”. The extension will allow for the pipeline to remain filled with nitrogen until it will be re moved/abandoned as part of the flowloop abandonment when the Na Kika facility is removed from the OCS.

Additionally, BP requests approval to depart from the requirements of 30 CFR 250.1006 (b)(3) until the Na Kika Field “end of life”. The extension will allow for the pipeline to remain in place until it is removed/abandoned as part of the flowloop abandonment when the Na Kika facility is removed from the OCS.


Very truly yours,/C-

Deborah R. Malbrough C JRegulatory Advisor

attachments

Deborah R. MatbroughRegulatory Advisor Deepwater GoM Region

BP Exploration & Production Inc.?(X) Westlake Park Boulevard - 471F Wl.4 Houston, Texas 77079 Telefrhonn 713-323-7090 Pi trail tJeborah.malbroughttbpcoro

June lb, 2014

Ms. Angie GobertChief, Pipeline UnitU.S. Department of the InteriorBureau of Safety and Environmental Enforcement1201 Elmwood Park BoulevardNew Orleans, Louisiana 70123-2394

RE: Extension RequestsWaiver from CFR 250.1006 (b)(2) Flush & Fill 8” BLKG Pipeline and Waiver from CFR 250.1006 (b)(3) Dccomission 8” BLKG Pipeline Pipeline Segment No. 13802, From MC 522 Sled SGi to MC 474 Na Kika Na Kika, Mississippi Canyon Block 474, Lease OCS-G 26259-Platform A

Ms. (k)bert:

BP Exploration & Production Inc. (BP) by letter dated January 8, 2013 requested an extension of the waiver received from 30 CFR 250.1006(b)(2) flush and fill Pipeline (PL) Segment N'o. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. (SN) 13802 has been out-of-service since April 2010. BSEE subsequently stamp approved the flush and fill waiver on January 11, 2013 to allow for an in-line inspection (ILI) to be completed for re-validation of the pipeline. The flush and fill waiver extension was approved through June 30, 2014 (attached).

By letter dated June 12, 2013, BSEE denied HP’s request dated June 6, 2013, to utilize an ILI tool in lieu of a hydrotest to revalidate PI. SN 13802 (attached). On September 25, 2013 BP met with the BSEE Pipeline Section to discuss PL SN 13802. By letter dateil November 12, 2013 (attached), BP submitted an Alternate Compliance Request to BSEE to utilize a combination of inspection methods to reinstate PI. SN 1381)2. The letter included information that BP presented in the September 2013 meeting and also detailed specific information details requested by BSEE.

On March 20, 2014, BP met with the BSEE Pipeline Sec tion and the Technical Assessment Section to discuss the request dated November 12, 2013. A revisec letter dated March 19. 2014 (attached) was delivered to BSEE at the meeting. To date. BP has not received a response from BSEE.

As such. BP requests an additional extension of the waiver from flushing and filling PL SN 13802. until December 31, 2015. The extension will allow for a response from BSEE and affords BP sufficient time to respond, plan, and execute an activity that allows for the revalidation and reinstatement of PL SN 13802

Additionally. BP requests approval to depart from the requirements of 30 CFR 250.1006 (h)(3), decommission the pipeline according to 30 CFR 250.1750-250.1754 ff‘r pipelines out of service for 5 or more years, until 1 lecember 31. 2015 to allow for the revalidation and reinstatement of PL SN 13802 as detailed above.

If you have any questions please, contact the undersigned at (713) 323-2090, on cell (713) 557*9453 or dehorah.malhroughfn bp.com.

Yerv tmlv vours.

Deborah R. Malbrough Regulatory Advisor ^

attachments

Deborah R. MalbroughRegulatory Advisor Deepwater GoM Region

BP Exploration & Production Inc.200 Westlake Park Boulevard - 471E WL4 Houston, Texas 77079 Telephone: 713-323-2090 Email: [email protected]

January 8,2012

Ms. Angie Gobert Chief, Pipeline Unit U.S. Department of the Interior Bureau of Safety and Environmental Enforcement Office of Field Operations1201 Elmwood Park Boulevard Pipeline SectionNew Orleans, Louisiana 70123-2394

RE: Extension RequestWaiver from CFR 250 .1006 Flush & Fill 8” BLKG PipelinePipeline Segment No. 13802, From MC 522 Sled SGl to MC 474 Na KikaNa Kika, Mississippi Canyon Block 474, Lease OCS-G 26259—Platform A

MineralB Management Senrioe

RECEIVED

Ms. Gobert:

BP Exploration & Production Inc. (BP) by letter dated December 16, 2011 requested a waiver from CFR 250.1006 from flushing and filling Pipeline Segment No. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. 13802 has been out-of-service since April 2010. BSEE subsequently stamp approved the flush and fill waiver on July 17, 2012 (attached).

The December 16, 2011 letter stated that BP was planning an in-line inspection (intelligent pigging) of this flowline loop in 2013. BP informs that the in-line inspection is now scheduled for February 2014. BP requests that the flush and fill waiver be extended to June 30, 2014 to allow for the February 2014 in-line inspection to occur and the results to be submitted to BSEE for re-validation of this pipeline.

If you have any questions please, contact the undersigned at (713) 323-2090, on cell (713) 557- 9453 or [email protected].

Regulatory Advisor

Approval is he/eby Date:

1 is nereoy anted.

4Ciick Wetzel

Regional Supervisor Bureau of Safety and Environmental Enforcement

Linda OnstottSf Regulatory Compliance Advisor Deepwater GoM Region

BP Exploration & Production Inc.200 Westlake Park Boulevard - 469 D W1 4 Houston, Texas 77079 Telephone 281-366-0219 Email: linda onstott@bp com

December 16,2011

Ms. Angie GobertU.S. Department of the InteriorBureau of Safety and Environmental Enforcement1201 Elmwood Park BoulevardNew Orleans, Louisiana 70123-2394

RE: Waiver from CFR 250.1006 Flush & Fill 8” BLKG PipelinePipeline Segment No. 13802, From MC 522 Sled SGi to MC 474 Na Kika Na Kika, Mississippi Canyon Block 474, Ixiase OCS-G 26259-Platform A

Ms. Gobert:

BP Exploration & Production Inc. (BP) hereby requests a waiver from CFR 250.1006 from flushing and filling Pipeline Segment No. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. 13802 has not seen production since April 2010. The F002 and the F006, wells that flow through this line, will be re-routed to produce through the East Anstey riser.

The segment had been blown down and the line likely contained a mix of gas condensate, MeOII, MEG, ind water. The March 2010 test data documents the water to gas ratios of 0.54 and 5.65, respectively. The technical authorities consider these to be low water to gas ratios.

The segment was de-inventoried in late July 2011 using N2 displacement. The N2 was bled down topsides. The sled valve SLDV-3552 passed a barrier test, proving its ability to contain pressure from the Segment No. 13797 side, and it has been mechanically locked closed since. Nakika has the ability to monitor the pressure in this isolated segment topsides at the boarding valve.

Na Kika operations, including the Production Chemist, have determined the segment is in a stable condition and flushing and filling with water would not necessarily contribute to flowline integrity.

• There are no bacteria in the line, as substantiated by sampling of well stock during production of F002 and F6, the wells that produced into Segment No. 13802.

• Na Kika utilizes MEG for corrosion mitigation in the South Gas loop and it is continuously injected into F002 and F006 during production. There is mechanism to automatically shut in each well if MEG is not injected.

• Na Kika production chemist understands that if the water in the line was corrosive, it likely wo aid have stabilized by now.

• Introducing seawater would revert back to an aerated state, as we have no means to deoxygenate the water.

The segment could be re-validated in the future as the need for any tie-ins arises. BP is planning inline inspection (intelligent pigging) of this flowline loop in 2013.

BP F'xploration & Production Inc. (BP) hereby requests a waiver from CFR 250.1006 from flushing and filling Pipeline Segment No. 13802 with inhibited seawater when the pipeline is out of service for more than one year but less than 5 years. Segment No. 13802 has not seen production since April 2010. The F002 and the F006, wells that flow through this line, are scheduled to return to production in early 2012.

The segment has been blown down and the line likely contains a mix of gas condensate, MeOH, MEG, and water. The March 2010 F002 and F006 well test data documents the water to gas ratios of 0.54 and 5.65, respectively. The technical authorities consider these to be low water to gas ratios.

Na Kika operations, including the Production Chemist, have determined the segment is in a stable condition and flushing and filling with water would not necessarily contribute to flowline integrity.

• There are no bacteria in the line, as substantiated by sampling of well stock during production of F002 and F006, the wells that produced into Segment No. 13802.

• Na Kika utilizes MEG for corrosion mitigation in the South Gas loop and it is continuously injected into F002 and F006 during production. There is mechanism to automatically shut in each well if MEG is not injected.

• Na Kika Production Chemist understands that if the water in the line was corrosive, it likely would have stabilized by now.

• Introducing seawater would revert back to an aerated state, as we have no means to de- oxygenatc the water.

The current plan is to de-inventory this segment using N2 in early August In late 2011 or early 2012, the entire south gas flow loop will be pigged and hydro-tested to prove integrity prior to restarting production utilizing PI. Segment No. 13802.

If you have any questions please, contact the undersigned at (281) 366-0219 on cell (713) 208-6176 or [email protected].

Sincerely,

Linda OnstottSr. Regulatory Compliance Advisor

Approval is hereby granted

nMek Wetzel Regional Supervisor bureau of Safety and Envi Enforcement nvironmental

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