Basis for Design New

CHESTER MEAD ASSOCIATES LIMITED

BASIS FOR DESIGN FOR

MIDWESTERN OIL AND GAS COMPANY PLC PROJECT:

UMUSADEGE CENTRAL PROCESSING FACILITY ENGINEERING AND PROCUREMENT SERVICES CONTRACT NUMBER:

xxxxxxxxxxxx DOCUMENT NUMBER:

EAL/UMUCPF/GEN/DOC/001

AO2

30/04/2012

Issued for Approval

Rev.

Date

Description

Originator

AD

KK

Released

Approved (Client)

Epic Atlantic Limited

Page 1

UMUSADEGE CENTRAL PROCESSING FACILITY ENGINEERING AND PROCUREMENT SERVICES BASIS FOR DESIGN - CMA/UMUCPF/MDR-GEN/DOC/003 Feb 28, 2012

Party

ADDITIONAL AGREEMENT / APPROVAL RECORDS Rev. Ind. Name Sign

Date

REVISION PHILOSOPHY

All revisions for review will be issued at R01, with subsequent R02, R03, etc as required. All revisions approved for issue or design will be issued at A01, with subsequent A02, A03, etc as required. Documents approved for Construction will be issued at C01, C02, and C03 respectively. Documents or drawings revised as “As built” will be issued as Z01, Z02 Z03 etc. Narrative sections revised from previous approved issues are to be noted in the table below and/or highlighted in the RH margin (using the appropriate revision status) thus: | A02 Previous revision highlighting to be removed at subsequent issues. Drawings/diagrams revised from previous approved issues are highlighted by 'clouding' the affected areas and by the use of a triangle containing the revision status. REVISION HISTORY Rev. No.

Date of Issue

R02 A01

28/02/12

Reason for change IDC MWOG Comments Revised Production Forecasts & Well Streams Data Deleted Offspec collection within CPF


Page 2


Table of Contents GLOSSARY 1.0

2.0

3.0

4.0

8

INTRODUCTION ............................................................................................. 15 1.1

Purpose ................................................................................................ 15

1.2

The Umusadege Field ........................................................................ 15

1.3

The Field’s Facilities Development Objectives .............................. 15

1.4

Overview of The Field’s Existing Processing Facilities .................... 15

KEY CONSIDERATIONS .................................................................................. 17 2.1

Mode .................................................................................................... 17

2.2

Brown Field Engineering / Strategy Fit............................................. 17

2.3

Field Life ............................................................................................... 17

2.4

Efficiency & Optimum Oil Recovery from the Process Systems .. 17

2.5

Dry Crude Export ................................................................................ 17

2.6

Zero Effluent Emission ......................................................................... 18

THE EXISTING FACILITIES & INFRASTRUCTURE............................................... 19 3.1

Surface Facilities in Place.................................................................. 19

3.2

The Early Production Facility ............................................................. 19

3.3

The Field Infrastructure ...................................................................... 20

DESIGN REQUIREMENTS ................................................................................ 21 4.1

Design Capacities & Specifications ................................................ 21

4.2

Well Fluid Characteristics and Properties ....................................... 22

4.3

Export Crude Specification............................................................... 22


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4.4

Produced Effluent Water Specification .......................................... 23

4.5

Characterised Well Fluid Data ......................................................... 23

4.6

Formation Water Analysis.................................................................. 24

4.7

Production Start-Up ............................................................................ 24

4.8

Erosion Velocity & Noise .................................................................... 25

4.9

Facility Standards ............................................................................... 25

4.10 Design Simulation Software .............................................................. 25 5.0

THE CENTRAL PROCESSING FACILITY ........................................................... 26 5.1

Facilities / Process Description ......................................................... 26

5.2

Design & Operating Philosophy ....................................................... 29

5.2.1 The Inlet and Intermediate / ESD Valves Manifold ....................... 30 5.2.2 The Test Separator .............................................................................. 31 5.2.3 The HP Separator ................................................................................ 31 5.2.4 The LP Separator ................................................................................ 31 5.2.5 The Gas Boot ....................................................................................... 32 5.3

The Crude Export Pumps ................................................................... 32

5.4

The Closed Drain System ................................................................... 32

5.5

Gas Handling ...................................................................................... 32

5.6

Flare System ........................................................................................ 33

5.7

Water Treatment ................................................................................ 33

5.8

Storage Tanks ...................................................................................... 33

5.9

Diesel Storage and Dispensing ........................................................ 35

5.10 Service & Fresh Water System .......................................................... 35 Epic Atlantic Limited

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5.11 Chemical Injection System ............................................................... 35 5.12 Pneumatic Control & Automation System ..................................... 35 5.13 Earthing System .................................................................................. 35 5.14 Cathodic Protection System ............................................................ 36 6.0

MWOG PROCURED EQUIPMENT ................................................................... 37

7.0

CIVIL WORKS ................................................................................................. 38

8.0

INSTRUMENTATION ........................................................................................ 39 8.1

Test Separator Instrumentation ........................................................ 39

8.1.1 Back Pressure Control ........................................................................ 39 8.1.2 Level Control ....................................................................................... 40 8.1.3 Level Measurement ........................................................................... 40 8.1.4 Low and High Level Safeguarding .................................................. 41 8.1.5 High Pressure Safeguarding.............................................................. 41 8.1.6 Pressure Measurement ...................................................................... 41 8.1.7 Gas Outlet Flow Measurement ........................................................ 41 8.1.8 Liquid Outlet Flow Measurement ..................................................... 42 8.1.9 Temperature Measurement ............................................................. 42

9.0

8.2

HP Separator Instrumentation .......................................................... 42

8.3

LP Separator Instrumentation ........................................................... 42

8.4

Crude Oil Export Pump Instrumentation ......................................... 42

8.5

Flare Knockout Vessel Instrumentation ........................................... 43

EQUIPMENT LAYOUT ...................................................................................... 44 9.1

AREA CLASSIFICATION ....................................................................... 44


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9.2

LAYOUT CONSIDERATIONS ................................................................ 44

10.0 FIRE PROTECTION .......................................................................................... 46 10.1 Fire Water ............................................................................................ 46 10.2 Fire and Gas Detection System ....................................................... 46 11.0 ELECTRICAL DESIGN BASIS ........................................................................... 47 11.1 Power Generation.............................................................................. 47 11.2 UPS ........................................................................................................ 48 11.3 Power Transmission & Distribution .................................................... 48 12.0 HSE/SD REQUIREMENTS ................................................................................. 49 12.1 Safety Considerations........................................................................ 49 12.2 Environmental Considerations ......................................................... 49 12.3 Security Considerations ..................................................................... 49 12.4 Risk Assessment and Management ................................................ 50 13.0 ASSET MANAGEMENT ................................................................................... 51 13.1 Operating Philosophies ..................................................................... 51 13.2 Asset Reference Plan......................................................................... 51 14.0 MANAGEMENT OF CHANGE & QUALITY ..................................................... 52 14.1 Design Change .................................................................................. 52 14.2 Quality Assurance and Control Requirements .............................. 52 15.0 STATUTORY AND REGULATORY COMPLIANCE ............................................ 53 15.1 Nigerian Content ............................................................................... 53 15.2 Regulatory Considerations ............................................................... 53 16.0 APPENDICES .................................................................................................. 56 Epic Atlantic Limited

Page 6


BFD Matrix ....................................................................................................... 56 Production Forecast / Well Fluid Characteristics and Properties ........... 56 Fire and Gas Detection ................................................................................ 56 Proposed General Layout ............................................................................ 56


Page 7

GLOSSARY The Following definitions and abbreviations have been used in this document. Organisational API

American Petroleum Institute

Client

Midwestern Oil & Gas Company Plc

Consultant

Chester Mead Associates Limited

CMA

Chester Mead Associates Limited

DPR

Department of Petroleum Resources

FME

Federal Ministry of Environment

MWOG

Midwestern Oil & Gas Company Plc

NAPIMS

Nigerian Services

NCD

Nigerian Content Division

Petroleum

Investment

Manageme


Page 8

CMA-MWOG UMUSADEGE CPF ENGINEERING DESIGN AND PROCUREMENT SERVICES BASIS FOR DESIGN - CMA/UMUCPF/MDR-GEN/DOC/004 June 9, 2012

Definitions and Abbreviations (continued) Technical Terms AC

Alternating Current

AG

Associated Gas

AGG

Associated Gas Gathering

ALARP

As low as reasonably practicable

BFD

Basis for Design

B/L

Bulkline

BS&W

Base Sediments & Water

CASHES

Community Affairs, Safety, Health, Environment and Security

CITHP

Closed-in Tubing Head Pressure

CNG

Compressed Natural Gas

cP

Centipoise

CP

Cathodic Protection

CPF

Central Processing Facility

CPP

Central Power Plant

CPU

Central Processing Unit

CCR

Central Control Room

DCS

Digital Control System

D/L

Delivery Line

EIA

Environmental Impact Assessment

EPF

Early Production Facility

ESD

Emergency Shutdown

FEED

Front End Engineering & Design


Page 9


FOB

Freight on Board


Page 10


Definitions and Abbreviations (continued) Technical Terms (contd.) F&G

Fire and Gas Detection System

F/L

Flowline

F/S

Flowstation

GGF

Group Gathering Facility

GTL

Gas To Liquids

GOR

Gas Oil Ratio (Surface)

HEMP

Hazard and Effects Management Process

HMI

Human Machine Interface

HP

High Pressure

HSE

Health, Safety and Environment

HV

High Voltage

HVAC

Heating, Ventilation and Air Conditioning

IGF

Induced Gas Flotation

ITC

Incoming Termination Chamber

I/O

Input/output

LACT

Lease Automated Custody Transfer

LCR

Local Control Room

LEL

Low explosion limit

LER

Local Equipment Room

LPG

Liquefied Petroleum Gas

L/P

Line Pipe

LP

Low Pressure


Page 11


LV

Low Voltage

Definitions and Abbreviations (continued) Technical Terms (contd.) MCS

Master Control Station

MOC

Management of Change

M/F

Manifold

OML

Oil Mining Lease

PAS

Protective Alarm System / Process Automation System

PAGA

Public Address and General Alarm

PES

Programmable Electronic Systems

PFD

Process Flow Diagrams

PID Control

Proportional-Integral-Derivative Control

PSD

Process Shutdown

P/L

Pipeline

RAM

Risk Assessment Matrix

SD

Sustainable Development

SDV

Shutdown Valve

SIMOPS

Simultaneous Operations

SPIR

Spare Parts List and Interchangeability Record

SRS

Safety Requirement Specifications

TMR

Triple Modular Redundant

TPI

Tilted Plate Interceptor


Page 12


Definitions and Abbreviations (continued) Units of Measurements BCF, bcf

Billion Cubic Feet

bpd

Barrels per Day

bopd

Barrels of Oil per Day

Bscf

Billion Standard Cubic Feet

bwpd

Barrels of Water per Day

CFM

Cubic Feet per Minute

Deg C

Degree Centigrade

ft

Feet

km

Kilometer

km/h

Kilometer per Hour

kVA

Kilovolts Ampere

m

Meter

M

Thousand

MBD

Thousand Barrels per Day

MM

Million

MMscfd

Million Standard Cubic Feet per Day

MMstb

Million Stock Tank Barrels

MMMscf

Billion Standard Cubic Feet

psi

Pounds per Square Inch

ppm

Parts Per Million

scf

Standard Cubic Feet

scf/b

Standard Cubic Feet per Barrel


Page 13


USD

United States Dollar


Page 14


1.0 INTRODUCTION 1.1

Purpose This document establishes the design criteria, outlines the system design, equipment and component design features, as well as the performance characteristics consistent with those criteria. The document also creates the framework for the instruction documents and construction specifications. The contents of this document represent the objectives of the owner, project engineers, and consultants in terms of design features, systems functionality, and performance.

1.2

The Umusadege Field Umusadege is a marginal field operated by Midwestern Oil and Gas Plc. The field is near Kwale in Delta State of Nigeria, and is situated in OML 56. The field’s current potential is 20 Mbopd, but is currently producing about 9 Mbopd, through an early production facility within the field, with the stabilised wet crude routed to AGIP via existing GGF and LACT systems.

Further development activities are

planned, which will maintain the field’s production at this level.

However, the

production forecasts from the new wells are yet to be reflected in the production forecast reference in this BFD 1.3

The Field’s Facilities Development Objectives The objective is to replace the existing 10 MBD early production facility with a 20 MBD nominal capacity Central Processing Facility of two trains.

Furthermore

opportunity will be taken at this stage to address and re-design HSE and operational deficiencies to bring the field’s operations to standard. 1.4

Overview of The Field’s Existing Processing Facilities The existing 10 MBD processing facility is a single train one-stage separation EPF, consisting of a 3-phase test separator, and 3-phase group separator, and related ancillaries. The produced crude is stored in rented tanks, from where it is pumped to a delivery pipeline for export through AGIP. The produced water is passed Epic Atlantic Limited

Page 15


through an oil skimmer tank and disposed to a pit. There is no AG facility and the associated gas is currently flared.


Page 16


2.0 KEY CONSIDERATIONS The key considerations are presented and summarized below. 2.1

Mode The CPF should be designed as a normally not manned facility. It should be able to operate safely under this mode, as well as being able to be shut down safely remotely from a PLC based control room. Its start-up has to be locally from the field, or remotely only with local permissive from the field.

2.2

Brown Field Engineering / Strategy Fit The design will consider the existing facilities in operation, and equipment already ordered, and the extent to which they may be incorporated in the design, without prejudice to HSE, operating standards, and undue production deferment.

2.3

Field Life The projected field life is 20 years, for which facilities life of 25 years shall be considered appropriate.

2.4

Efficiency & Optimum Oil Recovery from the Process Systems Number of separation stages will be optimized in the light of surface oil recovery and pressure regimes of the wellhead crude. In this respect more than one-stage separation will be considered for the higher pressure streams, as that will improve their oil recovery.

2.5

Dry Crude Export The design will include infield dehydration, as export will be through a 3rd party facility that is willing to accept only dry crude, BSW 0.5%, and TVP 10 psia at 82o F.


Page 17


2.6

Zero Effluent Emission The design will aim for total gas utilization and disposal of produced gas and water only

by

means

approved

by

client.


Page 18


3.0 THE EXISTING FACILITIES & INFRASTRUCTURE Existing processing facilities in the field are limited to the Early Production Facility (EPF) and rented storage tanks. There are no existing gas processing facilities. However, some equipment, – separators, gas boots, test and production manifolds have been procured for the planned facilities upgrade, viz:

1 No. Group Separator – 8’ x 40’, 20 Mbopd / 7.5 MMscfd / 4 Mbwpd capacity (already procured)

2 Nos. Gas Boot / Water Separator – 3.28’ x 40’ (already procured)

1 No. 6” Test Manifold

1 No. 8” Production Manifold

Also two storage tanks, each of 14.5 Mbbl capacity are currently being installed, and more may be installed later. 3.1

Surface Facilities in Place The surface facilities in place and in use are: •

The 10 MBD Early Production Facility

•

4 Nos. Wellheads

•

8 Nos. Wellhead Flowlines, with one of the flowlines hooked up directly to the Crude Storage Tank

3.2

•

1 No. Field Manifold, complete with Bulk Flowline and Test Line.

•

Group Gathering Manifold & Delivery Line

•

6 Nos. Rented Crude Storage Tanks

•

Crude Oil Metering System

The Early Production Facility The Early Production Facility is of an ad-hoc design, of one-stage separation, comprising the following: •

1 No. Test Separator, complete with Inlet Manifold with 6” Header and ESD


Page 19


•

1 No. Group Separator, complete with Inlet Manifold with 8” Header and ESD - One Bulk 3-Phase Separator

•

3 Nos. Crude oil transfer pumps

•

Oil saver skimmer / drain pit system

•

Diesel system

•

Instrument air system

•

Flare system - complete with flare liquid knock-out vessel

•

Service and fresh water system

•

Chemical (de-emulsifier) injection system

•

Power Generation System, - 1 No. 350 kVA & 1 No. 250 kVA Diesel Engine Sets

•

Drain Systems, complete with 2 drain water pumps that inject water from the storage tanks into the drain pit.

3.3

The Field Infrastructure The key field infrastructure comprise of the following: •

Custody transfer unit - 14,000 bpd capacity, complete with 6” bidirectional loop for meter proving

•

A new CAT 725 kVA Diesel Engine Set

•

Utility air generation, - 2 Compressors of 375 CFM at 120 psi and a self support test separator instrument air compressor

•

6 Nos. Crude storage tanks of 12,000 barrels total capacity

•

Effluent water handling capacity of 2,500 bpd.


Page 20


4.0 DESIGN REQUIREMENTS 4.1

Design Capacities & Specifications The production profile constructed from the field’s well streams forecasts is shown below, with potential production of 23 Mbpd as peak, declining steadily.

The

forecasts are from the present wells only, excluding future wells. The production potentials of the future wells are yet to be established but believed to be substantial to fully utilize what would be the installed capacity of the CPF. Field's Production Forcast Production Forecast

Year

Rate

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

Oil - Mbopd

19.6

17.6

15.8

14.3

12.8

11.6

10.4

9.4

8.4

7.6

6.8

6.1

5.5

5.0

4.5

4.0

3.6

3.3

2.9

2.6

2.4

2.1

1.9

Gas - MMscfd

3.5

7.9

8.3

10.4

10.4

9.6

8.5

6.9

5.5

4.7

4.3

3.8

3.4

3.1

2.8

2.5

2.3

2.0

1.8

1.6

1.5

1.3

1.2

W ater - Mbwpd

2.3

2.5

2.7

3.0

3.3

3.5

3.2

3.0

2.8

2.5

2.0

1.8

1.5

1.3

1.0

0.9

0.8

0.7

0.7

0.6

0.5

0.5

0.4

Projected at 10% decline, as supplied forecast did not cover the period

Field's Production Profile ‐ Constructed from Well Streams OIl Production Forecast 25.0

20.0

15.0

10.0

5.0

0.0 2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035


Page 21

2036


4.2

Well Fluid Characteristics and Properties

Serial No.

Subsurface Conditions W ell String

UM U 1 L

1

UM U 1 S

2

Oil

W ellhead / Surface Flow Conditions Wellhead

Reservoir /

Reservoir

Bubble

Datum Depth

Pressure

Point

Water

ft ss

psia

psia

cP

cP

XIIA/ 7 8 8 2

3,410

108

1.41

0.00

94

XIIB/ 7 9 5 0

3,430

110

0.80

0.00

Viscosity Viscosity

Rsi

Boi

API

Tank Oil

CITHP

FTHP

Temp

psig

psig

deg C

SG

(air = 1)

cs

1.400

650

230

96

0.83

0.84

0.00

71

1.40

800

300

96

0.85

0.86

0.00

scf/ stb rb/ stb

Tank Oil Gas SG

Viscosity

3

UM U 5 L

IX/ 7 6 0 6

2,947

116

0.73

0.00

120

1.40

500

320

130

46.00

0.00

0.00

5

UM U 6 L

XVI/ 8 1 4 5

3,410

372

0.70

0.00

100

1.12

680

420

151

44.00

0.00

0.00

6

UM U 6 S

XIIIA/ 8 1 0 5

3,408

364

0.71

0.00

140

1.12

660

340

145

40.00

0.00

0.00

7

UM U 7 L

XIV/ 8 2 3 7

3,522

570

0.64

0.00

127

1.12

780

410

140

44.00

0.00

0.00

8

UM U 7 S

XIIC/ 8 0 0 5

3,435

110

0.69

0.00

132

1.12

800

640

135

40.00

0.00

0.00

4.3

Export Crude Specification Reid Vapor Pressure (RVP) True Vapor Pressure (TVP) Basic sediment and water Salt content Storage Temperature

≤ 10.0 psia 10.5 psia @ maximum storage temperature ≤ 0.5 volume percent ≤ 35 lb/kstb ≤ 80 - 82 °F


Page 22


4.4

Produced Effluent Water Specification Maximum instantaneous dispersed oil content of produced water discharges will be ≤ 10ppm.

4.5

Characterised Well Fluid Data

Component

Mole %

Nitrogen Carbon dioxide Hydrogen sulphide Methane Ethane Propane i-Butane n-Butane i-Pentane n-Pentane Hexanes Heptanes Plus Octane Plus Nonane Decane Undecane Dodecane Tridecane Tetradecane Pentadecane Hexadecane Heptadecane Octadecane Nonadecane Eicosane Uneicosane Doeicosane Trieicosane Tetraeicosane Pentaeicosane Hexaeicosane Heptaeicosane Octaeicosane Nonaeicosane Triacontane plus

0.19 0.14 0.00 8.71 3.56 7.34 5.97 6.80 5.19 3.61 5.53 5.32 8.28 5.17 4.69 3.18 2.60 2.44 2.21 2.31 1.92 2.19 1.22 1.19 0.91 0.84 0.80 0.73 0.60 0.53 0.46 0.40 0.35 0.30 4.32

Total

100

Specific gravity

Molecular weight NBP (°F)

0.7227 0.7457 0.7648 0.7788 0.7898 0.8008 0.8118 0.8228 0.8328 0.8398 0.8478 0.8528 0.8578 0.8628 0.8679 0.8729 0.8779 0.8819 0.8859 0.8899 0.8939 0.8969 0.8999 0.9506

96 107 121 134 147 161 175 190 206 222 237 251 263 275 291 305 318 331 345 359 374 388 402 544

TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD TBD


Page 23


4.6

Formation Water Analysis Source Umusadege–6 Date Sampled SG pH Conductivity, µs/cm @ 80oF Resistivity, ohm.metre @ 60oF Total Dissolved Solids, mg/l Total Salinity, mg/l Total Alkalinity, mg/l Hydrogen Sulphide CATIONS Potassium, mg/l Sodium, mg/l Calcium, mg/l Magnesium, mg/l Barium, mg/l Iron, mg/l Strontium, mg/l ANIONS Chloride, mg/l Sulphate, mg/l Carbonate, mg/l Bicarbonate, mg/l

th

(BHS @ 7,965 ft)

8 February 2011

2nd March 2007

1.0104 7.83 @ 80oF 8,403

0.9980 @ 60oF 7.96 @ 20oC 5.900

4,820 4,250

1,380

665

1,727 16.5 3.7 45.0 0.4

23 295 145 3.6 1.2 0.8 0.7

2,303 35 25 640

460 8.5 Nil 445

Hydroxide, mg/l

4.7

Umusadege–4

Nil

Nil

Production Start-Up The CPF facilities will be designed to allow facility startup using the emergency (diesel) generator system, as black start. Facility operability during turn-down to level of 20% of design rates is anticipated.


Page 24


4.8

Erosion Velocity & Noise The optimum diameter for the interconnecting lines between Inlet headers and separators will be determined to ensure that flow velocities are within erosion limits and noise avoided.

4.9

Facility Standards This is necessary only in so far as is necessary to ensure variety control as well as the stocking and inter-changeability of spare parts.

4.10 Design Simulation Software The process design software shall be: HYSYS, Pipe Phase, Pipe Sim and Flare Net while the facility layout shall be designed with AUTOPLANT. Simulation data and results of analysis will be included in the design reports.


Page 25


5.0 THE CENTRAL PROCESSING FACILITY The base case concept for the Central Processing Facility is a 2 x 20 MBD capacity processing facility as shown in the PFD below, and will be developed with a provision for possible future tie-ins of additional separator(s). The 2-train system is driven by the objective to minimize production deferment through SIMOPS on the facilities installation, as well as optimal utilization of equipment already procured. Other related options are considered and analysed in the concept selection study report (with Document No. CMA/UMUCPF/MDR-GEN/DOC/004). The CPF systems include the following facilities: •

Oil processing and export facilities.

•

Well test facilities.

•

Utility and support systems operation.

•

Produced water treatment facilities.

5.1

Facilities / Process Description The oil processing involves two trains and 3-phase separation.

The trains

configuration and installation have been planned to minimize production deferment at transition. In this respect, the first train, Train-1, will be designed and installed to start on one-stage LP separation, with provision to use mobile test unit for well testing (to be evaluated), while the second train, Train-2, will be designed and installed with the full complement of multi-stage separation, including a test separator. The multi-stage separation will start with two stages, with provision for future XHP / XXHP installation as will be dictated by the pressure regimes based on input information provided on well 9. The design for the XHP / XXHP integration is outside the current scope of work, and will be implemented if and when the time comes •

Crude processing will be segregated between the two trains as follows: higher pressure wells to be processed via the 2-stage separation (HP + LP),


Page 26


while the lower pressure wells will be processes through the one-stage separation (LP). •

Piping will be configured for flexibility to flow any well through the HP train or LP train, as well as connectivity between the two trains.

•

The test separator, though will be installed in Train-2, will serve both trains. In addition valving will be designed for flexibility to use the test separator as bulk HP separator for Train-1.

Figure 1: Train 1 Flow Scheme


Page 27


Figure 2: Train 1 & 2 Flow Scheme

Both trains will enable produced oil to be routed through three cascade tanks each of size 1,000 barrels before export through the LACT, or transfer to storage tanks with cumulative capacity of 100,000 barrels for temporary if and when the need arises. A heater currently available has been converted to function as an LP separator. All separation stages are placed as three phase separators, enabling water to be removed from each stage as well as the gas boots, for processing in a TPI facility. The TPI produced water is anticipated to meet DPR specifications of 10 ppm oil in


Page 28


water before disposal in a water injection well, whose design is intended to be covered in a separate contract. In addition, given the fact that the produced water is planned to be disposed by injecting it into well(s), the need for treating to the high quality of 10 ppm needs to be discussed and confirmed with the DPR, to avoid the cost of achieving specifications that are unnecessary. The produced gas will be used as fuel gas for the CPF gas engine generator, with the excess available for external utilization. For the excess gas handling, five potential options have been compiled for evaluation, i.e.: 1. LPG recovery + power generated with surplus methane stream, 2. Power generated with whole stream of gas for export to National Grid, 3. CNG bottles manufactured by third parties, 4. Produced gas sold at CPF fence, 5. Gas injected into Umusadege reservoirs. This last option is only included only for completeness of the records and not considered to be a serious option, as DPR will not approve gas disposal by re-injection. Any or all of the options will be examined for potential uptake by third party offtakes or MWOG/partners, to enable a specific recommendation. This review will be carried out as part of the detailed engineering scope and will be reported separately. 5.2

Design & Operating Philosophy The CPF will be normally not manned


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It should be able to operate safely under this mode, as well as being able to be shut down safely remotely from a local PLC based control room. The PLC will be equipped with HMI, and SCADA capability. Its start-up has to be locally from the field, or remotely from the control room only with local permissives from the field. The operating modes outlined in this philosophy shall be developed during detailed engineering. 5.2.1 The Inlet and Intermediate / ESD Valves Manifold The inlet manifold will operate in bulk and test mode and both modes can be operated concurrently. The bulk mode will be the normal production mode in which wells with the same pressure regime are switched to the same header where they are commingled. From the header, they flow into a targeted (HP or LP) or in some cases test separator (when the test is being operated in bulk mode). The test mode will be the mode in which a well is put under test to determine its production capacity and basic composition such as GOR and BS & W. In this mode, the well under test will be switched to the test headers from where it flows into the test separator. The inlet headers are process lines between the ligaments and the inlet separators. Each well and also each inlet header will have individual shutdown valves, which is used primarily to isolate the ligaments (wells and flow lines) from the inlet separators during an operational or emergency shutdown. On each bypass line is a 2 inch manual globe valve. The bypass line is used primarily during start-up to gradually pressurize the flow station and the instrument fuel gas header by the use of the 2 inch globe valve. The flow station is first pressurized before each header ESD valve can be opened for the following reasons:•

Enable the lighting of the flare.

•

Prevent a pressure shock (hammer effect) on the facility.

•

Prevent possible damage of the header ESD valves seat because of high differential pressure across them.


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•

Allow a reset of the pneumatic safeguarding panel.

Each header ESD valve will consist of a ball valve with a spring return actuator. A pneumatic pilot operated three-way valve operates the actuator. The pilot signal on the three-way valve will be controlled by a pneumatic relay based safeguarding system. Pressure gauges are installed on each header to measure the inlet pressure. 5.2.2 The Test Separator The test separator operates as 3-phase. It will have two operating modes (test and bulk). When in test mode, any of the wells under test is routed to the test separator. In the bulk mode, it will be used for normal production and operates like any of the other two separators (LP & HP). In this mode, all producing wells within the same pressure regimes are switched manually through their individual ligament valves into the test header. From the test header they flow into the test separator. 5.2.3 The HP Separator The HP Separator will operate between 220 to 240 psig. All producing wells within the same pressure regimes are switched manually through their individual ligament valves into the HP header. From the HP header they flow into the HP separator. In the separator, liquid and gas are separated. The flashed gas exits though the gas outlet, while the oil and water stream is routed to the LP separator. 5.2.4 The LP Separator The LP separator will operate between 30 to 40 psig. All producing wells within the same pressure regimes are switched manually through their individual ligament valves into the LP header. From the LP header they flow into the LP separator.

The oil, water and gas are separated. The flashed

gas exits though the gas outlet, while the oil is routed to the gas boot / surge vessel.


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The water is routed to the water treatment facility. 5.2.5 The Gas Boot The gas boot is a three phase degassing / stabilizing unit, also enabling additional refinement of de-oiled water to be routed to the water treatment facility for further processing. Final separation of gas and liquid occurs in both cases, the flash gas exits through an outlet line and flows into the flare knock-out vessel. The liquid (oil) exits through the outlet line where it flows by gravity into the cascade tanks, from where it is pumped to the LACT. Details of pump control will be developed with vendor data during detailed engineering. Pump discharge pressure floats on the pipeline operation pressure, which is a function of the liquid export flow rate and the other users of the pipeline system. 5.3

The Crude Export Pumps Centrifugal pumps, with variable speed drive mechanism have been procured to be used. These pumps are already on the site and will be evaluated to assure they fit the required duty.

5.4

The Closed Drain System All vessel drains are routed to the closed drain sump tank.

Recovered oil is

pumped back to the crude oil export system while removed water is routed for treatment. Open and closed drainage systems shall be included. Open drains will channel rain water and non-hazardous fluids to the open drain pit via the open drain header. Closed drains handling oil contaminated and hazardous liquids are routed to the closed drain tank via the closed drain header. 5.5

Gas Handling Associated gas will be routed to an AG solution facility to enable value addition for sales.

Options that may be considered for the AG solution facility include

processing for direct sales, or for LPG extraction and power generation, for own use or for sale. Epic Atlantic Limited

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A fuel gas system shall be provided for supply of fuel gas to the gas turbines. The fuel gas system shall be sized to supply all future equipment required for the Design Case. Supply pressure will be based on selected gas engine generator. A purge gas system shall be provided for purging and supply to flare pilots and ignition system. Critical control valves shall be spared to ensure availability of supply. 5.6

Flare System In line with DPR regulations, routine process flaring will not be permitted. However a full facility flare will be included for use under emergency conditions. The existing flare will be evaluated to determine capacity for the forecast production. A flare header / flare system will be provided to collect and safely dispose of produced hydrocarbon gases. As a minimum, the system will consist of flare headers, a flare knockout drum, and a continuously ignited pilot flare. In addition, the system will be designed to safely and continuously flare the produced gas capacity of the CPF and to depressurize all of the production flow lines in the shortest possible practicable time.

Discharges from pressure relief valves and

other hydrocarbon streams as required by the CPF Facility Specifications will be routed to the flare system.

The flare system will be equipped with meters to

measure flare volumes to within an accuracy of ±2%. 5.7

Water Treatment Produced water will be routed to a TPI (Tilted Plate Interceptor) Facility ahead of disposal. The ultimate disposal route will be via re-injection into an aquifer. The TPI produced water shall be made to meet DPR specifications of 10 ppm oil in water before disposal by injection into an aquifer. Before the installation of the water injection plant, water will be disposed off in the existing pond. The design of the injection facility is outside the scope of this Basis for Design, and will be covered in a separate contract.

5.8

Storage Tanks The tables below summarise the tanks that will be installed: Epic Atlantic Limited

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Table 1:

Crude Oil Tanks

Tank Designation

Capacity

Processed (dead) Crude

2 x 14,500 barrels

Processed (dead) Crude

2 x 35,000 barrels (Anticipated)

Crude Settlement

3 x 1,000 bbl Cascade Tanks

Table 2:

Other Tanks

Tank Designation Produced Water Firewater Chemical (one per chemical type) Diesel

Capacity 1,000 bbl as part of re-injection phase. 5,000 barrels TBD 500 barrels (10 days endurance)

The crude oil tanks will be fitted with a stripping system to permit removal of water that has settled out of the crude oil. The storage system will be capable of receiving stabilized crude from the production facilities. The offloading system will be capable of discharging at a rate and pressure such that it can flow into the GGF. Fiscal metering of the exported crude will be based upon the use of the existing LACT system at GGF since the existing facility is in-place and is reliable. The tank shall be fitted with local flow meters (or gauge). The facility and associated systems will be designed to remain on site for entire design life and with minimal maintenance and repair (e.g., no major steel, coating, and piping or equipment renewals) which might result in interruption of production operations. This will be achieved mainly from material selection. There will an automated and manual level control system on each tank. Motorised valves will be interlocked to allow one tank filling at a time. Two 14,500 barrel crude oil tanks shall be used for storage and settlement. Additional two 35,000 barrels capacity are anticipated for future expansion. The storage tank inlet motorized valves are controlled by the Level Switch High on the storage tank to prevent overfilling of the crude oil. The motorized valves are also at interlock with each other with the philosophy that only one tank can be Epic Atlantic Limited

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filled at a time. The closure of one motorized valve gives an advent of the opening of the next motorized valve on priority. The Level Switch Low on the tank control the motorized valve on the outlet section of the tank in safeguarding the operation of the pumps. The final logic of the tank filling operation shall be done by the detailed engineering contractor which shall be implemented by the Vendor of the Programmable Logic Controller. 5.9

Diesel Storage and Dispensing Diesel is required for the emergency power supply system. Specific care will be made to ensure that the supplied quality meets equipment requirements and that adulterated products are not supplied.

5.10 Service & Fresh Water System Potable water system will be included for use in engine cooling system as well as fire water storage. The borehole supply pump will be powered by electric motor. 5.11 Chemical Injection System Chemical Injection points will be included where needed.

Such chemicals as

corrosion and scale inhibitors are potentially required. 5.12 Pneumatic Control & Automation System Dry instrument air will be provided to the process facilities. CMA will determine the required pressure and capacity of the instrument air and provide 2 or 1 electric motor driven air compressors.

CMA shall consider the cooling demands of

generator when assessing the instrument air demand. An air filtration (leaning) regulator system will be provided. 5.13 Earthing System An earth ring main will be designed to provide earthing source for all the facilities


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5.14 Cathodic Protection System Cathodic protection will be provided for buried flowlines & delivery line and also for vessels and storage tanks.


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6.0 MWOG PROCURED EQUIPMENT The following equipment items have been procured and, as much as is feasible, will be included in the design. Table 1:

Pre-Ordered Equipment Items

Tag

Dimensions

MAWP

Design Temperature

Test Separator

1.1m by 3.1m

655 psig

200OF

L.P Separator

8ft OD x 40 ft s/s

50 psig

140F

H.P Separator

5ft OD x 20ft s/s

740 psig

200F

Gas Boot

1 m x 14m

20 psig

140F

Test Manifold

6 in header

1,400 psig

120OF

Production

8 in header

1,400 psig

120OF

Storage Tanks

65ft dia x 24 ft

5 psig

Ambient

Pump

67.6 HP

187 psi

(Rating)

(Differential)

Manifold

Technical information on these items of equipment are available and will be applied in the design checks.


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7.0 CIVIL WORKS The scope of civil works covers the following aspects: 1. Determine the facility area including fence lines, roads and footprints of facility components. This shall be based on survey maps and as-built drawings provided by MWOG, which shall be verified during site visits. 2. Appraise existing drainage lines and reconcile with new routing required. 3. The topography of the new CPF area shall be reviewed to ascertain the extent of cut and fill that will be required. 4. Output from topography review shall form basis for recommending heights of supporting structures; e.g. pipe supports, tanks, vessels and gas boots foundations, steel columns, and walkways. 5. Detailed design of all applicable foundations including oil tank foundations, control room, buildings, skids, bundwalls . Results of the borehole sampling will be reflected in the design work and shall form the basis of foundation design. 6. Detailed instructions on materials to be used, method of application, expected results or outputs and technical development for constructing the works stated in item 5 shall be adequately provided. 7. Recommend any other structural component required for a resilient structure; e.g. platforms, walkways etc. 8. The Construction Scope of Work. These items relating to the execution and completion of construction works shall be quantified and priced as input to the project cost estimate. It is expected that any modifications and change orders from the client shall be incorporated as civil works progress, if agreed and accepted by parties.


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8.0 INSTRUMENTATION Overall control of the liquid production system is through the Process Automation System (PAS). This extends over the pump stations, tank farm and the CPF. The facility will be normally not manned. Normal monitoring of plant performance, verification of set-points and starting/stopping of equipment, etc, will take place from the Control Centre located at base. The Flowstation oil production system will be maintained in stable operation by a number of factors, including manually set flowlines choke valves that will maintain the overall station production 8.1

Test Separator Instrumentation The test separator instrumentation will be designed to provide a means to initiate and carry out well testing locally, and in line with API 14C will have the following features: •

Back Pressure Control

•

High Pressure Safeguarding

•

Level Control

•

Low & High Level Safeguarding

•

Level & Pressure Measurement

•

Gas Outlet Measurement

•

Liquid Outlet Measurements

•

Temperature Measurement

8.1.1 Back Pressure Control The test separator will be designed to operate at either LP or HP separator pressure, and in test or bulk mode. Hence, it will not have a dedicated back pressure control system, but will share with that of the LP separator (when in LP mode) or the HP separator (when in HP mode). This sharing shall be implemented by connecting the test separator gas outlet line to both the LP or HP header where their back pressure control systems are installed. The back pressure control will comprise a pneumatic pressure controller and pressure control valve.

The pressure controller measures the process


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pressure and produces a standard pneumatic output signal, which drives a back pressure control valve. 8.1.2 Level Control The level control will comprise the following: a.

Displacer type controller / transmitter

b.

Level control valve

c.

Test / Bulk mode selector switch

d.

Level Measurement Displacer Type Controller / Transmitter The displacer type pneumatic transmitter receives change in fluid level through change in buoyant force exerted by the fluid on the sensor displacer, and consequently produces a standard pneumatic output signal that drives the control valve. Test / Bulk Mode Selector Switch The liquid outlets will be divided into two, - a 2” and a 4” line, with a level control valve installed in each line, with both lines recombined into a 4” line downstream of the control valves. The required liquid outlet line (2” for test mode, and 4” for bulk mode) is selected by manually opening of the ball valves upstream and downstream of the level control valve, while the control valve selection is by use of a manual pneumatic switch. The pneumatic selector switch connects the standard output signal of the level transmitter / controller to the selected valve. The liquid outlet will be divided into oil & water to achieve metering separately.

8.1.3 Level Measurement The only level indication will be that directly on the vessel by the use of sight glass. There will be no direct level measurement and display on the test separator except level measurement by the displacer type transmitter / controller used


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in the level control loop. The level control loop will be primarily field located with no form of indication. 8.1.4 Low and High Level Safeguarding The test separator will be equipped with a duplex type transmitter and controller that will provide dual function of level control and high / low level safeguarding. The safeguarding instrumentation will consist of high and low level displacer type pneumatic switches, connected to a pneumatic relay panel used for plant safeguarding. The safeguarding logic is implemented in the relay panel such that for a high level in bulk mode, all the inlet valves and the liquid outlet valve are closed. In the test mode, the inlet valve applicable will be that of the well on test. In the event of low level, the liquid outlet valve will be forced down. Other safeguarding functions will be conducted in accordance with the flowstation’s cause and effects diagrams 8.1.5 High Pressure Safeguarding The test separator high pressure safeguarding will comprise a high pressure pneumatic switch that will initiate the shutdown. When the pressure switch senses a high pressure, it sends a signal to the pneumatic safeguarding relay panel, where the shutdown logic is implemented in accordance with the cause & effects diagram. The objective is to close the inlet shutdown valve to the separator so as to prevent further entry of hydrocarbon. 8.1.6 Pressure Measurement All pressure measurement will be by pressure gauges only. 8.1.7 Gas Outlet Flow Measurement A senior Daniel orifice or ultrasonic meter will be installed to measure all outlet gas rates.


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8.1.8 Liquid Outlet Flow Measurement Oil & water will be metered separately.

The oil will be measured using

turbine meters for accuracy that will be in line with DPR requirement. 8.1.9 Temperature Measurement All temperature measurements will be by temperature gauges only. 8.2

HP Separator Instrumentation The instrumentation and safeguarding functions on the HP separator will be similar to the test separator, except that there will be no liquid measurement, only gas. Similar to the test separator, it will have a duplex type level instrument, which will provide both level control and high – high level safeguarding function.

8.3

LP Separator Instrumentation Also, the instrumentation and safeguarding functions on the HP separator will be similar to the test separator, except that there will be no liquid measurement, only gas. Similar to the test separator, it will have a duplex type level instrument, which will provide both level control and high – high level safeguarding function.

8.4

Crude Oil Export Pump Instrumentation The crude oil pump will have a pneumatic governor, which will be used to vary the speed of the pump gas engine driver as part of the level control system of the surge vessel. When the level in the surge vessel goes high, the speeds of the pumps are set to maximum by the surge vessel controller.

At low level, the

pumps are set to minimum speed. In the event that the level drops further, the recirculation valve begins to open so as to recycle the liquid to the surge vessel. Pressure gauges will be installed on the pump suction and discharge lines.


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8.5

Flare Knockout Vessel Instrumentation The knockout vessel will have four level switches. Three of the switches will be electric, while the fourth will be pneumatic two of the electric switches will be used for level control, while the third will be used to shutdown the pump on low – low level detection. The pneumatic switch will be connected to the pneumatic relay panel for shutdown on high – high level in the flare knockout vessel. The level control system for the pump will consist of a stand-alone electric relay logic control panel.


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9.0 EQUIPMENT LAYOUT The facility equipment shall be laid out to fit within the CPF land boundary, bearing in mind the limitations created by the position of the new storage tanks under construction and right of way. 9.1

AREA CLASSIFICATION Adequate safe distances for all equipment will be considered in accordance with area classification requirements that will be firmed up at detail design stage. The layout shows access roads with provision for drainage lines. Inter-connecting piping from the process area to storage tanks will be buried at road-crossings; i.e. piping at other areas will be above ground. The allocation of functional spaces in the layout was based on the following parameters: • • • • • •

Flare zone: North-West, due to prevailing wind directions Utility area: North, in the proximity of the administration building, considered as a safe area Tank farm: South-West, in the largest free space to accommodate tanks Process area: South-East, in near proximity to in-coming lines and inlet manifolds Fencing: Perimeter of property, and seal-off of restricted areas. Accesses: Gates to control service accesses into restricted areas

A conceptual layout is included as Appendix to this document. 9.2

LAYOUT CONSIDERATIONS 1. All equipment will be placed optimally, satisfying the optimum orientation for all processes, utility and instrument equipment items. 2. The cost of construction will be minimized, e.g. by adopting a layout that gives the shortest run of connecting piping between equipment. 3. Sufficient working space and headroom will be provided to allow easy access to equipment. Epic Atlantic Limited

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4. Equipment such as pumps that require dismantling for maintenance will be placed under rain/sun cover. 5. Equipment will be located so that it can be conveniently tied in with any future expansion of the process, e.g. future gas off-take. 6. Additional space will be left along the pipe racks to accommodate future piping needs. 7. The gas flare that is included for emergency use will be located as far as possible from the process vessels, in line with safe area classification requirements. 8. The EPF will be tied-in to the new storage tanks via temporary transfer lines that would be disconnected before commissioning the CPF. 9. The general plant arrangement and orientation will be consistent with the prevailing atmospheric and site conditions such as wind direction as well as hazardous area requirements. 10. Adequate allowance will be left for drainage and fire fighting facilities. Access ways will be provided within the facility for access to items that require removal for off-site repair.


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10.0 FIRE PROTECTION 10.1 Fire Water Fire water storage tank shall be installed with a capacity suitable to meet firefighting needs for a minimum period of four hours, as determined by the period for arrival of firefighting support equipment from nearby locations. A diesel fuel pump and electrical Jockey pump are included. The critical areas shall be covered with a pressurized ring main that feeds a series of hydrants each with hoses located at strategic positions in the CPF. 10.2 Fire and Gas Detection System A Fire and Gas Detection System shall consist of three parts: a) Detection b) Control Logic c) Active Protection Fire and Gas Detection devices and Manual Call Points shall be provided. The System shall provide voting capability (2oo3 and where there is failure in one of the applicable detectors, it recourses to 1oo2) where multiple detectors have been installed to minimize nuisance shutdowns. For a large area with multiple zones (without a barrier), cross zone voting within adjacent zones may be used. Process shutdown actions initiated by the Fire and Gas Detection System shall be executed via interlocks to the ESD/PSD systems. Other actions (e.g., release of fire suppressant systems, fire water pump starts, etc.) may be executed directly from the F&G System. The Fire and Gas Detection System shall be designed so that it can be functionally tested and individual detectors can be calibrated without affecting CPF processes and equipment operation. The system configuration for F&G Systems shall comprise centrally located logic solvers in the control room and either centrally or remotely located I/O systems.


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Further details on the proposed fire protection system are contained in a separate document in the Appendix.

11.0 ELECTRICAL DESIGN BASIS Power will be generated using gas engine generators fired by the produced gas. A diesel engine set will be retained for emergency power. Furthermore, solar power will also be considered as that will have prime use for critical installation such as the CP system or the telemetry system for communications between the wells and the CPF. 11.1 Power Generation Power will be generated on site with two adequately sized Gas engine generator operated in an N+1 sparing philosophy and sized to cater for 100% total plant peak load, covering the CPF, GGF, Campsite, and Satellites.

The required for

future facilities, e.g. water injection plant and AG solution facility will be addressed separately, when the time comes. In addition to the gas engine generators, a diesel engine generator shall be provided for emergency service and cold start of the CPF. The emergency generator shall be adequately sized to supply power for vital and agreed essential services and to start and run a minimum of one oil export pump. The vital services refer to those services which, when they fail in operation or when called upon, can cause an unsafe condition of the process and / or electrical installation, jeopardize life, or cause major damage to the installation; while the essential services refer to those that when they fail in operation or when called upon, will affect the continuity, quality or quantity of the product. The emergency and critical loads will be defined and agreed, and reflected in the load list. The load list will form the basis for load segregation, as well as sizing main equipment such as: 1.

Main gas engine generators

2.

Emergency diesel generators

3.

HV switchboards

4.

LV switchboards

5.

Protective circuit breakers etc.


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11.2 UPS AC and DC uninterruptible power supply shall be provided complete with battery banks for the vital loads at the CPF and outlying flowstations. The uninterruptible power supplies shall use Nickel Cadmium batteries. Each power supply shall be equipped with two 100% duty chargers capable of both charging batteries and supporting the maximum load. All batteries shall be 2 x 100% sized, and capable of supporting their for 30 minutes.

11.3 Power Transmission & Distribution Power transmission will not be required because the low voltage distribution can be used. Main power distribution within the facility will be at 415/220 volt, 50Hz, TPN (Triple Phase and Neutral) in accordance with local power authority (PHCN) standard distribution. Power will be distributed to electrical equipment by adequately sized cables via cable trays or trench. Adequate protections will be provided to electrical equipment and personnel on site through a well-designed earthing network that will tie into the existing earthing system. Other deliverables will be generated in line with the approved MDR.


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12.0 HSE/SD REQUIREMENTS HSE issues are those which result from the interaction of the proposed facility with the environment and safety related issues that need to be addressed as part of Human Factors Engineering in design and also, during project implementation in the Umusadege field. CMA’s CASHES Plan has been consistently applied in our work execution, enabling safe working practices and minimum impact on the environment or damage to human life. Documents created as part of the design activities will reflect these perspectives. 12.1 Safety Considerations The general approach adopted during design development and the requirement for further design stages will identify and eliminate hazards as an integral part of the design process. 12.2 Environmental Considerations The PMT and HSE regulatory teams will work closely together to assure environmental issues are considered in the design process, following the applicable regulations and guidelines listed in section 15.2.

An Environmental

Impact Assessment study has been conducted on the facility and all its recommendations shall be implemented. All new facilities will be installed under the existing MWOG operating permit. 12.3 Security Considerations CMA / MWOG are committed to a dynamic, visible security program, which addresses the threats in the major following areas: •

Protection of assets

•

Office and Residential Security

•

Personnel Transportation/Travel

•

Communication/Information Security


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12.4 Risk Assessment and Management The CPF project has a number of inherent risks and uncertainties. These will range from sub-surface uncertainties that may affect the production forecast, to technical and commercial risks, but also include a number of socio-political risks, especially during the project execution phase at Umusadege. A risk register has been compiled with 80 items listed.

Mitigation factors will be developed and

implemented. This project will follow standard guidelines for Engineering Managed Modifications (EMM) as part of the process for managing any associated risk. A Design Risk Assessment shall be conducted before the detailed design is concluded. As part of risk assessment, a specific perspective is the need to carry out a SIMOPS exercise during detailed design.

Consideration will be given to

simultaneous operation of the EPF in parallel with the installation of the CPF. A SIMOPS Study will be carried out to assess the risks and develop the right approach for risk mitigation during the installation CPF stage.


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13.0 ASSET MANAGEMENT 13.1 Operating Philosophies Operating philosophy envisages that the facility is not normally

manned.

Maintenance will aim at preventive maintenance through a computerized management system. Other features include the following: a.

Field production will continue un-hindered during the installation of the expanded facility. Aspects include placement and tie-in of processing vessels and piping works in tandem with systems in operation.

b.

Considering that the Umusadege is a marginal field, sparing of equipment items will be minimized. Also for this reason, high integrity systems will be included for process safety control. Moderate level of automation for process control is desired, with process control equipment placed in a purpose-built office.

c.

The facility will operate 365 days a year with shut-down only in the event of an emergency procedure or for statutory inspections on relief systems and vessel internals.

13.2 Asset Reference Plan The ARP that will be created by others at the end of detailed design will aim to utilize the Operations Readiness and Assurance report to: •

Define the boundaries of the asset.

•

Optimize asset planning and operations with respect to previously completed sub-surface

studies,

facilities

design

and

equipment

selection

and

specifications •

Integrate business process strategies,

All these actions are aimed at optimizing value of the asset for benefit of MWOG, its partners, and other stakeholders.


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14.0 MANAGEMENT OF CHANGE & QUALITY 14.1 Design Change All changes that interface with MWOG operations will be captured, using the CMA Management of Change (MOC) process. This would ensure that potential changes are properly assessed, approved and documented so that risks remain at acceptable levels while project objectives are met. All necessary approvals will be secured before any deviation / change is carried out. 14.2 Quality Assurance and Control Requirements CMA’s Quality Assurance process will be applied through the concept of competence in work disciplines and the attitude and commitment that mandates all staff to follow best practices.


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15.0 STATUTORY AND REGULATORY COMPLIANCE This design shall follow the guidelines and standards set by Midwestern Oil and Gas, Department of Petroleum Resources (DPR) and International Codes of Practice as applicable in the oil industry. Safety standards shall follow the regulations from the Occupational Safety and Health Act (OSHA) and other Nigerian regulations. 15.1 Nigerian Content The work shall be done in accordance with the Nigerian Content Development Regulation passed by the National Assembly in 2010. Nigerian contractors will fabricate and install, in most cases using Nigerian personnel. 15.2 Regulatory Considerations The Umusadege project will be developed in compliance with all applicable Nigerian laws and regulations. The project will also be guided by Scope of work specifications and International Codes and standards referenced therein.

The

Nigerian Department of Petroleum Resources (DPR) is the responsible government entity for regulating petroleum development in Nigeria.

Other pertinent

government agencies involved directly or indirectly, in engineering, procurement, construction, and installation activities in oil and gas development include: •

Federal Ministry of Environment (FME)

•

Nigerian National Petroleum Corporation (NNPC)

•

Nigerian Petroleum Investment Management Services (NAPIMS)

Applicable Regulations and Guidelines related to oil and gas exploration and exploitation activities include but are not limited to the following: •

MWOG joint Operating Agreement

•

Petroleum (Drilling & Production) Act 1969

•

Mineral Oils (Safety) Regulations 1997

•

Guidelines and Procedures for Construction, Operation and Maintenance of Oil and Gas Pipelines and Ancillary Facilities issued by DPR

•

Environmental Guidelines and Standards issued by DPR, 2002


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The design shall reference industry and international codes and standards. The engineering work carried out in this project complies with applicable government regulations, industry standards including, but not limited to those listed in Appendix 1, and are deemed most applicable to the scope of this project. In all cases the latest edition of the codes shall be used except otherwise stated for older/existing components. CMA will operate within the tenets of Company’s standards. Drawings for all new facilities shall comply with all applicable international standard. Specifically;

MWOG

Project scope of work and other documents from MWOG

MWOG

Design instructions from MWOG staff

MWOG

Information gathered during facilities site visit

Nigeria

All applicable Nigerian Codes and Standards

Unfired

Pressure ASME Boiler & Pressure Vessel Code (Section II, Section

Vessels

Section VIII, Div. 1 or Div. 2, and Section IX)

Process Facilities

All applicable API RP (e.g. API RP 14E, 12J etc).

Relief Valves

ASME Section VIII, API 520, 521, 526, 527

Piping

ANSI B31.3, Code for Chemical Plant and Petroleum Refine Pressure Piping

ANSI/ASME B16.5 Steel Pipe Flanges and Flanged Fittings ANSI/ASME B16.9 Wrought Steel Butt welding Fittings ANSI/ASME

Steel Socket Weld Fittings

B16.11 ANSI/ASME

Metallic Gaskets for Pipe Flanges - Ring Joint, Spiral Woun

B16.20

and Jacketed

ANSI/ASME

Valves - Flanged, Threaded and Weld End


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B16.34 API 598

Valve Inspection and Testing

API 600

Steel Gate Valves - Flanged and Butt welding Ends

API 602

Compact Steel Gate Valves

API 650

Welded Tanks

API 12B

Bolted Tanks

ASME 8

Boiler and Pressure Vessel Code

Electrical

All apparatus shall bear the CSA label All installations shall be in accordance with the CSA Nation Electrical Code, latest edition.

API RP 500

Recommended Practice for Classification of Locations f Electrical Installation at Petroleum Facilities

NFPA

National Fire Protection Association

NFPA 10

Fire Extinguishers

NFPA 12

CO2 Extinguishing System

NFPA 13

Sprinkler System

NFPA 14

H2O Spray fixed system

NFPA 14

Standpipe and Hose system

NFPA 20

Fire Pumps

Other NFPA are; 16, 15, 22, 72, 30, 54 and 101


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16.0 APPENDICES BFD Matrix

BFD Matrix.pdf

Production Forecast / Well Fluid Characteristics and Properties

Production Forecast & Profile Picture.xls

Fire and Gas Detection

Fire and Gas Detection System.doc

Proposed General Layout

Proposed General Layout.pdf


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Basis for Design New

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