CTC044 - BP-SBM-L-0039

RESTRICTED

Angola Strategic Performance Unit

BP Angola Programme Process Technical Note (Flare)

Document Number:

ANG-PROG-20-BP-FAC-TEC-0005

Document Revision:

A1

Copyright © BP Angola Programme 2006 All rights reserved None of the contents of this document shall be disclosed, except to those directly concerned with the subject and no part of this document may be reproduced or transmitted in any way or stored in any retrieval system without the prior written permission of BP Angola Programme general management.

ANG-PROG-20-BP-FAC-TEC-0005 BP Angola Programme Process Technical Note (Flare) ANGOLA PROGRAMME : Document Control Sheet Title:

BP Angola Programme Process Technical Note (Flare)

Company/Dept:

BP ANGOLA PROGRAMME

Author(s):

Tania Roach, Nick Aldis

Owner:

Nick Aldis

Preparation Date:

Date document was prepared 11/Nov/2008

Abstract:

The purpose of this note is to convey lessons learned from a flare header incident that occurred on a BP facility resulting in a high potential gas release.

Document Number:

ANG-PROG-20-BP-FAC-TEC-0005

Classification:

RESTRICTED SURF

FPSO

Sub Surface

Operations

Drilling & Completions

Programme Management

Procurement /Contracts

Project Services

HSE

Exploration

Commercial

Asset

Internal Notification:

Programme Engineering

Appraise / Select

Other: External Notification:

Partners

Contractor

Approved by: Approval:

M. Hodgkinson Martin Hodgkinson, FPSO Engineering Team Leader, Angola Programme

Hardcopy Location

Original signed copy to be passed to BP Document Control Manager for central filing Programme

FPSO

SURF

Drilling & Completions

Pre-Operations

Appraise & Select

SubSurface

Sector Relevance

Revision Control A1 01 Rev

Issued for use Issued for comment Description

08/Dec/08 13/Nov/08 Date

TMR TMR Prepared

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NMA NMA Checked

MGH MGH Approved

ANG-PROG-20-BP-FAC-TEC-0005 BP Angola Programme Process Technical Note (Flare)

EXECUTIVE SUMMARY The purpose of this note is to convey lessons learned from a flare header incident that occurred on a BP facility resulting in a high potential gas release. It should be noted that the information associated with this incident is confidential and is to be used solely on BP projects. BP expects contractor to review and act on the following recommendations which are summarised below and detailed in the subsequent sections of this document: 1. The slope of all flare headers shall be designed to ensure 1:100 under all anticipated vessel trim and list operating scenarios, as detailed in this document. This requirement shall be clearly marked on all relevant engineering drawings e.g. P&IDs, piping isometrics 2. During detailed design the FPSO contractor shall produce a detailed piping study of the flare and drain header networks to ensure confirmation of header slope and that routing is free draining under all anticipated operating scenarios. This document must be reviewed and approved by BP prior to construction. Subsequent changes will be by MOC and endorsed by relevant competent people in the contractor and client teams. 3. The flare headers and sub-headers will be designed for No Pockets as far as practical and clearly marked on engineering drawings such as P&IDs and piping isometrics. Where designing for No Pockets is not practicable provision for drainage is required. 4. Pressure and temperature transmitters will be provided on flare headers. 5. Confirm the requirement for a Glycol Contactor pressure control valve to flare during detailed engineering. 6. The routing and segregation of fluids into the flare system must be reviewed for all programme FPSOs to ensure that cold uninhibited gas cannot be allowed to enter wet gas flare systems for prolonged periods of time. 7. Isolation of inlet and outlet cooling medium lines to shell and tube exchangers shall meet the highest form of integrity as per Institute of Petroleum Guidelines (Ref 1). 8. Operating guides to be developed for all process systems (especially gas system) that indicate abnormal operating modes such as flaring to maintain production in addition to steady state “normal” operation. In addition, these guides should clearly identify the safe operating envelopes for start up, shutdown and normal operation. The Angola Programme FPSO contractors are required to demonstrate to BP how the above recommendations have been incorporated into the FPSO design. Many of these recommendations are considered good engineering practice and should not present additional effort over and above what is expected as part of FEED and detailed engineering activities.

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The above actions shall be included into a formal Hazard tracking process and will require BP approval, supported by documentary evidence where appropriate, to assure close-out.

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Contents 1

INTRODUCTION....................................................................................................6

2

DESCRIPTION OF EVENT ....................................................................................7

3

KEY FINDINGS ......................................................................................................8

4

KEY RECOMMENDATIONS TO BE ADDRESSED IN PROGRAMME DESIGN 10 4.1

Flare Header Drainage ................................................................................10

Recommendation 1: ....................................................................................................... 10 Recommendation 2: ....................................................................................................... 11 Recommendation 3: ....................................................................................................... 11

4.2

Pressure Instrumentation.............................................................................12

Recommendation 4: ....................................................................................................... 12

4.3

PCV to Flare on Glycol Contactor ...............................................................12

Recommendation 5: ....................................................................................................... 12

4.4

Segregation of Fluids...................................................................................13

Recommendation 6: ....................................................................................................... 13

4.5

Safe Isolation of Cooling Medium Lines ......................................................14

Recommendation 7 ........................................................................................................ 14

4.6

Safe Operating Envelopes...........................................................................14

Recommendation 8: ....................................................................................................... 14

5

REFERENCES ......................................................................................................16

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1 INTRODUCTION A high potential incident occurred on a BP facility resulting in a significant gas release. The purpose of this note is to briefly describe the incident and its causes and to convey lessons learned from this incident. This note makes recommendations relating to process and piping system design, management of change processes and development of system operating guides. BP expects contractor to review and act on recommendations contained herein.

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2 DESCRIPTION OF EVENT An incident occurred on a BP FPSO facility on Saturday, 16 August 2008. A blockage occurred in the “wet” HP flare header due to liquid accumulation and subsequent freezing by cold gas (-28Deg C) as a result of prolonged flaring of both wet gas from the Slug Catchers and cold gas from the top of the Glycol Contactor. Both vessels were flaring to the same HP wet flare header simultaneously. This ice/hydrate blockage led to pressure rises in the flare header to c. 20-30 bar. Within seconds, rupture discs on the MP gas compression coolers gave way, followed by the HP gas compression coolers. In total, rupture discs on five of the ten gas compression coolers had burst as a result of reverse rupture from the flare system. Pressure transmitters in the cooler shells sensed the high pressure and triggered compressor shutdowns. The resulting action was to isolate each compression train individually and blow down the compressor cases and knockout drums to flare. The HP compressors blew down to the un-blocked dry (cold) flare header. However, the MP compressors blew down to the still-blocked HP wet flare header, further increasing the inventory connected to the blocked header. Simultaneous with the blowdown, the seawater inlet and outlet XVs on all the coolers were commanded to close. Event logs show that 18 of the 20 valves closed within ~15 seconds. However, both the inlet and outlet valve on the HP Train 1 first stage discharge cooler (X-33101) failed to close. In the seconds prior to the remainder of the valves closing, a large volume of gas would have escaped into the seawater discharge header. This gas quickly found its way to the disposal caissons, primarily the starboard-aft caisson, as this is located nearest the gas coolers. The unclosed cooler XVs on X-33101 acted as a flow path for gas entering the HP wet flare header. The outlet seawater line from the exchanger was restricted by the temperature control valve in this line, which went to its default position of 5% open. Therefore the primary path of gas out of the cooler was reverse flow back into the seawater supply header. Hydrocarbon gas release occurred via this route to the seawater caissons which resulted in topsides detection near the overboard water disposal caissons. This resulted in a Yellow Shutdown and subsequent full facility blowdown The facility was subsequently shutdown for a prolonged period whilst remedial work was carried out.

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3 KEY FINDINGS Process Finding 1: Free water was able to accumulate in the HP Wet Flare Header. The source of water was saturated gas flared from the first vessels in the separation process (inlet Slug Catchers). Issues encountered: •

The Flare headers were not free draining back to the flare drum under all anticipated operating scenarios. The need to provide a continuous slope was not stated on the P&IDs or reflected in the final piping design. The flare header design was ‘flat’ relative to the FPSO deck and this was deemed sufficient due to the anticipated trim of the vessel, expected to be down towards the flare drum. However the trim requirement was not documented to support flare header functionality in operations.

•

‘No Pockets’ was stipulated on the P&IDs, although an expansion loop, added to the layout of the HP wet flare header late in the design of the process, did not compensate for the full range of vessel list and trim, leading to liquid holdup in the flare header. Although the loop was technically ‘flat’, with respect to the FPSO main deck, and therefore had ‘No Pockets’, this would be true only when the vessel was perfectly level. This late design change was not communicated to appropriate people in the project.

Process Finding 2: Sub-freezing (-28Deg C) gas was flowing from the top of TEG contactor into the HP wet flare header for an extended period of time in combination with wet gas from the Slug Catchers. Issues encountered: •

Gas streams to flare were not appropriately segregated between the wet and cold HP flare headers.

•

The PCV off the top of the glycol contactor was intended to operate in the following scenarios: o During start up of the glycol system to enable gas to achieve dew point specification before commencing gas injection or gas lift. o As a mitigation to avoid lifting the glycol contactor PSVs in the event of sudden pressure rise due to HP compression shut-down.

•

It was never envisioned that the PCV would be operationally flaring for long durations. Production flaring was intended during start-up and for short durations following compressor upsets via the Slug Catchers.

•

The design made provision for methanol injection upstream of the PCV to flare should the water content of the gas be off-spec. The injection of Methanol was covered by operational procedure.

•

The interaction between MP compressor discharge pressure override in the performance controller and the Glycol Contactor PCV to flare pressure Page 8 of 16


controller was not implemented as the design of the process control system had intended. The override was to reduce load on the MP compressors by flaring from the Slug Catchers. The set point of the MP compressor second stage discharge pressure override was not intended to be higher than the opening point of the PCV to flare on the Glycol Contactor. The intended setpoints for the high pressure override and PCV to flare was 112barg and 113barg respectively. The override function was left disabled during commissioning. As a result of these controllers not being implemented correctly during commissioning, prolonged flaring from the Glycol Contactor occurred before MP compressor cut back.

HP Wet Gas Flare Header To Flare Horizontal Exp. Loop High Pressure Override + AntiSurge Limit loop

Suction Pressure Control

P PC

P

Gas Dehydration 105 barg, 35°C

P SC

From Wells MP Compression Slugcatcher 29 barg, ~52°C

(2 x 50%)

Seawater Disposal Caisson

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Dry Gas to HP Compression (2 x 50%)


4 KEY RECOMMENDATIONS TO BE ADDRESSED IN PROGRAMME DESIGN The following key recommendations are to be addressed by the FPSO contractor in the design of the facility.

4.1 Flare Header Drainage Recommendation 1: The slope of all flare headers shall be designed to ensure 1:100 gradients under all anticipated vessel trim and list operating scenarios, as per guidance by The Institute of Petroleum (Reference 1). This requirement shall be clearly marked on all relevant engineering drawings e.g. P&IDs, piping isometrics. This specification of a slope of 1:100 is applied generally to offshore systems and must recognise the variation in vessel trim associated with floating production systems. In addition to a slope of 1:100, the vessel orientation possibilities should be taken into account, i.e. the design should ensure that slopes are provided to ensure a fall in all reasonable foreseeable conditions of trim and list. The following are considered normal operating scenarios for topsides: 1.

Cargo oil tank loading and unloading conditions

2.

Hull tank inspection and repair conditions

In these conditions the flare headers shall drain correctly and there should not be any special interventions required. Likewise all other piping including drains should function normally. The Trim and Stability Report should demonstrate that the topsides design list and trim are not exceeded during inspection/repair offloading cycles. The topsides flare headers should also account for other abnormal conditions such as the dynamic portion of the inclination – e.g. dynamic rotation (pitch). For these abnormal conditions an additional drain valve at the aft end of the flare headers may be considered (see later – recommendation 3). The simple diagrams below are used to illustrate flare header slope requirement. Accommodation is shown at one end of the vessel, and the flare at the other. •

Offshore flare headers to be designed with a slope of 1:100, at all foreseeable trim and operating scenarios, e.g. Cargo Oil Tank loading/offloading, tank inspection and repair, etc.

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Stern

•

1:100

Bow

If, for example, normal operations include up to 1º trim1 at stern, the flare header would therefore need to account for 1º (1:57) and 0.573º (1:100) as per IP guidelines, i.e. 1.573º or 1:36. Note that 1:36 is relative to an axis on the FPSO, which is deemed to give a 1:100 slope of the flare header relative to sea level.

1:36 Stern

Bow

Recommendation 2: During detailed design the FPSO contractor shall produce a detailed piping study of the flare and drain header networks to ensure confirmation of header slope and routing is pocket-free, which is expected as part of good engineering practice. This document will be reviewed and approved by BP prior to construction and subsequently confirmed by site survey in the construction yard. Subsequent changes will be under a management of change procedure reviewed and endorsed by relevant competent people in the contractor and client teams BP. The Piping Document will outline the expected trim and list (static inclinations) of the vessel and demonstrate free draining can occur under all anticipated operating scenarios. This should address the slope required for various systems (not just flare) by piping direction e.g. stern to bow/transverse etc. The document will contain piping isometrics detailing the pipe lengths, fall and orientation of main flare and drain headers and sub-headers. Recommendation 3: Flare headers and sub-headers will be designed for No Pockets. This requirement shall be clearly marked on all relevant engineering drawings e.g. P&IDs, piping isometrics. Where designing for No Pockets is not

1

Please be clear that this degree of trim if for illustrative purposes only. Page 11 of 16


practicable, pockets and expansion loops in the flare headers and sub-headers will require drain points. Drainage schemes off the flare headers/pockets should be evaluated e.g. valved systems (e.g. “dead man valve” type) or a drip legs with a restriction orifice are feasible however FPSO contractor must follow guidance provided in API code and GP 44-80. Additional valving will be required to allow valve/RO maintenance and cleaning. Since the fluids can be volatile careful consideration of the routing of these fluids must be given whilst recognising BPs requirements for a closed drains system. If routed to the cargo, slop tanks or HC gas blanketing header the potential for gas blow-by must be assessed and addressed in the design. In general the use of drain pots with automated valves, switches or pump-out requirements should be avoided as the increased complexity associated with these schemes can reduce system reliability. However they can be considered on an exception basis. Note that the requirement for no pockets shall also apply to PSV tail-pipes which shall be designed to ensure free drainage on the discharge side of the PSV.

4.2 Pressure Instrumentation Recommendation 4: Provide pressure and temperature transmitters on flare headers. This will allow for confirmation of back pressures and temperatures in the header such that dynamic flare studies will be validated giving credibility to the flare design. The location and type of the transmitters on the HP Wet, HP (cold) Dry and LP flare headers shall be determined in detailed design. The risks associated with the fatigue of small bore connections from acoustic induced fatigue and turbulence induced fatigue must be considered for example – use of non-intrusive temperature instruments may provide sufficient temperature monitoring requirements. Pressure transmitters could be located at the upstream end of the headers in order to sense downstream blockage.

4.3 PCV to Flare on Glycol Contactor Recommendation 5: Confirm the requirement for a Glycol Contactor pressure control valve to flare. For the programme gas treating and gas compression system configuration, a PCV off the glycol contactor would normally be required to operate in the following scenarios: 1. To reduce the likelihood of the PSVs off the contactor lifting in the event of an HP compressor trip

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2. To allow start-up of the gas treating system and ensure gas can achieve the dew point specification before starting HP gas compression In order to confirm the requirement for the Glycol Contactor PCV in scenario 1, the hydraulic response of the designed system shall be checked by the FPSO contractor during detailed design through simulation modelling to ensure the PSVs on the glycol contactor do not lift if one or both HP compressors trip with the PCV to flare not operational. Firstly, an operable steady state condition must be demonstrated when the MP compression unit is operating in full recycle and all gas is flared via the HP separator flare pressure control valve(s). If steady state operation is proven, then the dynamic response of the system in transition from normal operating scenarios to HP compression shutdown should be simulated. The pressure in the glycol contactor must remain below the glycol contactor PSV set point without the action of the glycol contactor flare PCV and all other operating constraints must be met. The FPSO contractor must also demonstrate a safe and operable method of startingup the glycol contactor/dehydration system should this flare valve be considered unnecessary. Should studies confirm the requirement of the glycol contactor PCV, provision must be made for flaring off the contactor with the following restrictions/qualifications. •

The operating conditions must be clearly defined for the valve i.e. pressure, temperature, composition, worst case J-T cooling etc and any risks associated with acoustic of turbulent induced fatigue.

•

Consider removal of any wet gas bypasses around the glycol contactor to limit likelihood of wet gas flaring.

•

Consider routing the glycol contactor flare valve to HP cold flare header. Temperatures are anticipated to be low and liquids are not expected to be produced in any significant volume. See later recommendation on segregation.

•

Ensure methanol is injected upstream of PCV during off spec (wet gas) flaring. Consider automating this methanol injection.

If the PCV is retained, the MP compressor high discharge pressure override set point shall be lower than that of the PCV to flare off the glycol contactor to reduce the likelihood of continuous prolonged flaring from this PCV. Set points shall be verified by dynamic simulation. Further, this PCV can be used when starting up, however it is anticipated glycol will be recirculating at temperature before significant gas volumes are brought forward for HP compression.

4.4 Segregation of Fluids Recommendation 6: The routing and segregation of fluids into the flare system must be reviewed for all programme FPSOs to ensure that cold uninhibited gas is not being allowed to enter wet gas flare systems for prolonged periods of time. Page 13 of 16


Routes to flare and flare headers themselves must be clearly designated on P&IDs, PFDs and SFDs into the following:

HP wet flare header (VHW)

HP cold flare header (VHC)

LP flare header (VL)

For example, it is expected that the PCVs off the HP separators and MP compression trains will be routed to the HP wet flare header. The potential to route high pressure cold gas, e.g. glycol contactor and HP compression system, to the cold/low temperature flare header must be considered. This should include consideration of blowdown and relief valves where they may be leaking or failed (failed open).

4.5 Safe Isolation of Cooling Medium Lines Recommendation 7: Isolation of inlet and outlet cooling medium lines to shell and tube exchangers shall meet the highest form of integrity as per Institute of Petroleum Guidelines (Ref 1). On Greater Plutonio it was noted that 2 out of the 20 XVs on the shell and tube exchangers failed to close after the bursting discs had ruptured due to inability to close against such high pressures. This resulted in the primary path of HP wet flare gas through the cooler and reverse flow back into the seawater supply header. As it transpired, the failure of these XVs to close possibly prevented a larger incident occurring. However the design intent of the XVs was to prevent hydrocarbons entering the seawater system in a burst tube scenario and to vent safely via the bursting discs to flare assuming a free flow path. Institute of Petroleum guidelines section 3.7.4.4. state that an ESD valve may be fitted on outlet pipework whilst the inlet can have a check valve. However it goes on to recommend that higher integrity isolation can be afforded by also fitting an ESD valve upstream of the check valve on the inlet line. BP requires this higher form of integrity for applications where tube rupture is considered a risk.

4.6 Safe Operating Envelopes Recommendation 8: Operating guides to be developed by the FPSO contractor for all process systems (especially gas system) that describe abnormal operating modes (such as flaring to maintain production) in addition to steady state “normal” operation. In addition, these guides should clearly identify the safe operating envelopes for start-up, shutdown and normal operation. For this specific lesson, the operating guides must seek to align operating procedures for wet gas flare systems on all Programme FPSOs with the different system bases of design. Page 14 of 16


Gas system operating guide is to clearly outline the reasoning for the MP compressor discharge pressure set point being lower than that of the glycol contactor, i.e. to ensure any process flaring due to compression capacity limitations occurs off the HP separators and not from the glycol contactor. Operating guides to provide clarity on where points where continuous flaring cases/scenarios can occur. For example, continuous flaring can occur from the HP separators and LP compressors only, i.e. no prolonged continuous flaring from the glycol contactor. An inherently safe design approach should be utilised such that active and procedural protection is avoided.

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5 REFERENCES 1. Guidelines for the safe and optimum design of hydrocarbon pressure relief and blowdown systems, The Institute of Petroleum, 2001 2. Pressure-relieving and Depressuring Systems, ANSI/API Standard 521, 5th Edition, January 2007 3. GP 44-80 Guidance on Practice for Relief Disposal Systems, BP Group Engineering Practices, March 2006.

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CTC044 - BP-SBM-L-0039

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