WELL TEST OPERATIONAL GUIDELINES.pdf

WELL TEST OPERATIONAL GUIDELINES

THIS MANUAL IS CONTROLLED

CONTROLLED COPY NO: _____

This manual and the information contained therein is the property of Expro. It must not be reproduced in whole or in part or otherwise disclosed without the prior consent in writing from the Manager Operations Support.

DISTRIBUTION LIST

TITLE BASE NAME REF

OPERATIONS MANAGER HOUSTON T PARKIN 001

PRODUCT SUPPORT SPECIALIST ABERDEEN 003

REGION DIRECTOR ABERDEEN N ASHTON 004

WELL TEST MANAGER ABERDEEN G SIMS 030

WELL TEST SUPERVISOR ABERDEEN G MACDONALD 027

PRODUCT DEVELOPMENT MANAGER ABERDEEN D CLELAND 028

OPERATIONS SUPPORT ENGINEER ABERDEEN C CRAIG 011

TECHNICAL MANAGER ABERDEEN R MAIR 034

AREA MANAGER YARMOUTH W OWEN 008

WELL TEST SUPERVISOR YARMOUTH A ROSS 010

OPERATIONS SUPPORT ENGINEER YARMOUTH B GOOCH 012

AREA MANAGER SINGAPORE D BOWMAN 015

BUSINESS DEVELOPMENT MANAGER AFSU M MOXEY 013

OPERATIONS SUPPORT MANAGER YARMOUTH G PEEK 031

TECHNICAL SUPERVISOR AFSU D WOODEN 014

HSEQC MANAGER AFSU A HANNAH 079

WELL TEST SUPERVISOR AFSU T JONES

WELL TEST SUPERVISOR AFSU D BROWNE

TECHNICAL MANAGER AFSU B LESTRANGE

BUSINESS DEVELOPMENT MANAGER AFSU T CAMMERATA

AREA MANAGER WEST AFRICA AFSU G MORGAN

REGION DIRECTOR HOLLAND A KITCHENER 017

OPERATIONS SUPPORT HOLLAND M MEINSTER 019

WELL TEST SUPERVISOR HOLLAND C SOUTER 018

MAINTENANCE SUPERVISOR HOLLAND H EVERS 035

REGION DIRECTOR AUSTRALIA S ASHTON 021

WELL TEST MANAGER AUSTRALIA K McCARTAN

REGIONAL OPERATIONS MANAGER AUSTRALIA P BURTON

GENERAL MANAGER NORWAY J MACBEATH 005

OPERATIONS SUPERVISOR TUNISIA S DRAKE 009

OPERATIONS MANAGER VIETNAM S MOLLOY 022 & 023

GROUP MANAGER NIGERIA P STYLES 025

AREA MANAGER CHINA K CRAWFORD 007

BUSINESS DEVELOPMENT MANAGER AMERICA J LOAFMAN 029

CLIENT ACCOUNT MANAGER P GHEZ 033

OPERATIONS LIBYA S DRAKE 031

OPERATIONS ABERDEEN G MACDONALD 050 to 059

OPERATIONS YARMOUTH A ROSS 070 to 079

OPERATIONS HOLLAND N TIELENS 090 to 099

& 100 to 109

INTRODUCTION

This manual and revisions to it are under controlled distribution. Your name, and the number of the manual assigned to you, is kept on a master list maintained by the Surface & Environmental Systems Business Stream. Manuals for Operational use are assigned to the relevant Supervisor or Manager and it is their responsibility to ensure that all copies are updated with relevant amendments as issued.

Receipt of this manual and subsequently revised pages shall be acknowledged in writing, by signing or initialling a copy of the transmittal memo and returning same to the Surface & Environmental Systems Business Stream. Outdated pages shall be destroyed and revised pages inserted in the manual. Each transmittal memo to you should be inserted in the manual behind the index.

Un-registered copies of this manual are available for the use of Clients and prospective Clients.

This manual is the property of The Expro Group and is to be returned upon request, or termination of its usefulness to the holder in conduct of Expro business.

Custody of this manual may be transferred to another employee only with the knowledge and approval of the Surface & Environmental Systems Business Stream.

Surface & Environmental Systems Business Stream Aberdeen

AMENDMENTS AND RE-ISSUES

1 The Testing & Environmental / Support Department reviews the Manual periodically with other departments to re-affirm its adequacy and conformity to current requirements. The minimum frequency for review of the Manual is once each 2 years.

2 Amendments to the Manual when requested are undertaken to reflect the current Company Safety Standards, legal requirements and additional, new and modified equipment. The amendments are made by replacement of applicable page(s). Each amendment page is identified by amendment number and date of each amendment. Amendments will be issued to the relevant sub-sub-section but only recorded on the Amendment Record of each sub-section.

3 Amendments are numbered consecutively until such times as a new issue incorporates all changes. When changes affect a considerable number of pages and in any case after not more than ten amendments to one issue, the Manual is re-issued. Issues are identified by letters in alphabetical order. Each issue cancels and replaces all previous issues and amendments.

4 The Amendment Record indicates all the amendments to the latest issue of the Manual.

5 All Operating Guidelines clearly state whether Operating Guidelines revisions servicing is provided, and a complete list of Manual holders is retained by the Manager, Operations Support. Amendments and re-issues of the Manual are automatically distributed to all registered holders of controlled copies.

6 Personnel wishing to propose amendments or additions to this manual should use the Proposal Form or similar, outlining the proposal and reasons for the amendment or addition. Proposals should be discussed in the first instance with the immediate Supervisor or Manager who will then pass the proposal to the Manager, Operations Support for consideration for inclusion. A sample Proposal Form can be found at the end of this manual.

This procedure is a mandatory requirement and forms part of the Approved Well Test Operating Manual.

Alterations are not permitted without the prior approval of the Manager Operations Support.

AMENDMENT RECORD

1.0 GENERAL OPERATING GUIDELINES 1.0 Risk Assessment 1.01 Responsibilities 1.02 Definitions 1.03 Procedure 1.04 Risk Ratings 1.05 Actions 1.06 Records

1.07 Updating Risk Assessments 1.1 Pre-Test Planning 1.1.1 Rig Visit 1.1.2 Engineering Requirements 1.1.3 Hazop Studies 1.1.4 Equipment Maintenance 1.1.5 Certification 1.1.6 Pre-Test Meetings 1.1.7 Equipment Requirements 1.1.8 Personnel Mobilisation 1.2 Pre-Test Work Site Guidelines 1.3 Rig Visit Guidelines

1.4 Gas Well Testing 1.4.1 Problems

1.4.2 Operating Procedures 1.5 Oil Well Testing

1.5.1 Problems 1.6 Solids Management

1.6.1 General / Solids Production 1.6.2 Sand “Frac-Clean ups” 1.6.3 Sand Separator

1.7 High Pressure/Temperature Well Testing 1.7.1 Problems

1.7.2 Sub-Surface Capability 1.7.3 Data Acquisition 1.7.4 15,000 psi Equipment 1.8 Foaming Oil Well Testing

1.8.1 Problems in Handling Foaming Oil 1.8.2 Operational Guidelines

1.9 Sour Gas Well Testing

1.9.1 Effect of H2S on Equipment

1.9.2 Stress Cracking 1.9.3 Equipment Fabrication 1.9.4 Pyrophoric Ignition

1.9.5 Training for Personnel Prior to Test 1.9.6 Operational Guidelines

1.9.7 Supervisory Responsibility 1.9.8 Artificial Resuscitation Methods 1.10 Acid Clean Up Procedures

1.11 Post Test Guidelines

TABLES

1-1 Toxicity of Hydrogen Sulphide Gas 1-2 EXPRO's Recommended H2S Policy

APPENDIX 1

Fig. 1.1 Sour Gas Systems Fig. 1.2 Sour Multiphase Systems Fig. 1.3 Artificial Resuscitation Methods

2.0 PRESSURE TESTING GUIDELINES 2.1 Pressure for Field Pressure Testing

2.2 Duration of Pressure Tests and Mediums Used

2.3 Pressure Test Guidelines for Individual Items of Equipment 2.3.1 Surface Test Tree (on Deck)

2.3.2 Sand Filters

2.3.3 4 Valve/5 Valve Choke Manifolds 2.3.4 Heat Exchangers 2.3.5 Separators 2.3.6 Gas Diverters 2.3.7 Oil Diverters 2.3.8 Surge Tanks 2.3.9 Gauge Tanks 2.3.10 Freestanding Valves 2.3.11 Screwed Pressure Fittings 2.3.12 Erosion Probes ½" NPT 2.4 Example Pressure Test Diagrams 2.5 Post Pressure Testing Guidelines APPENDIX 2

Fig. 2.1 Line Up for Flushing System

Fig. 2.2 Starboard and Port Oil and Gas Lines to Burner, Surge Tank Inlet Valves Fig. 2.3 Function Test High Pilot (PSH) between Heat Exchanger and Separator and

Actuated Surface Safety Valve

Fig. 2.4 Starboard and Port Oil and Gas Diverter Lines Fig. 2.5 Oil Manifold Inlet Valves

Fig. 2.6 Surge Tank Body

Fig. 2.7 Separator Vessel and Outlet Valves Fig. 2.8 Separator Inlet and Bypass Valves Fig. 2.9 Heater Coils and Bypass Valves Fig. 2.10 Heater Inlet and Bypass Valves Fig. 2.11 Low Pressure Pilot (PSL2) Fig. 2.12 Surface Safety Valve

Fig. 2.13 Choke Manifold and Downstream Valves Fig. 2.14 Choke Manifold Upstream Valves Fig. 2.15 Low Pressure Pilot (PSL1)

Fig. 2.16 Hydraulically Actuated Flow-Wing Valve and Flowhead Master Valve Fig. 2.17 Remote ESD Stations

3.0 EQUIPMENT OPERATING GUIDELINES 3.1 Equipment Hook-up

3.1.1 Tubing Head Swivel 3.1.2 Surface Test Tree 3.1.3 Control Panel

3.1.4 Coflexip Hoses Hook-up 3.1.5 Pipework

3.1.6 Twin Pot Sand Filters 3.1.7 Data Headers

3.1.8 Choke Manifold Hook-up 3.1.9 Heat Exchanger 3.1.10 Relief Valve Skid 3.1.11 Phase Test Separator 3.1.12 Gas Diverter Manifold 3.1.13 Oil Manifold 3.1.14 Gauge/Surge Tank 3.1.15 Transfer Pump 3.1.16 Burner Booms 3.1.17 Burner/Ignition System 3.1.18 Burner Heads 3.1.19 Pressurised Laboratories 3.1.20 Dead Weight Tester

3.1.21 Surface Pressure/Temperature Recorder 3.1.22 Texsteam Chemical Injection Pump 3.1.23 Steam Generator

3.2 Lower Master Valve 3.2.1 Manual Valve

3.2.2 Hydraulically Actuated Valve 3.3 Temperature Sub

3.4 Chemical Injection Sub 3.5 Tubing Head Swivel 3.6 Surface Test Tree

3.6.1 Hydraulically Actuated Valves 3.6.2 Manual Valves

3.7 Control Panels

3.7.1 Resato SPP-10 Control Panel 3.7.2 Hydratron Single Circuit ESD Unit 3.8 Surface Safety Valves

3.9 Coflexip Hoses 3.10 Pipework

3.10.1 Minimum Allowable Wall Thickness 3.10.2 Thickness Checking

3.10.3 Hammer Unions 3.10.4 Clamp Connections 3.10.5 Flanges

3.10.6 Relief Line Capacities 3.11 Twin Pot Sandfilters

3.11.1 Equalising Pots

3.11.2 Diverting Flow via Duty Standard Pot

3.11.3 Switching from Duty to Standby Pot (Standard) Pots 3.11.4 Diverting Flow via Duty Pot (Double Block Pot) 3.11.5 Switching from Duty to Standby Pot (Double Block) Pots 3.11.6 Draining Standby Pot

3.11.7 Using the Dual Isolation System 3.11.8 Switching from Duty to Standby Pot 3.12 Data Headers

3.13 Chokes and Choke Manifolds 3.13.1 Choke Manifolds 3.13.2 McEvoy Model 'H2' 3.13.3 Foley Model 'FH2' 3.13.4 Masterflo Chokes 3.14 Heat Exchangers

3.15 Freestanding Relief Valves 3.16 Gas, Oil and Water Separators

3.16.1 General Operating Guidelines

3.16.2 Setting Back Pressure with Wizard 4150 Controller 3.16.3 Lowering/Raising Orifice Plate

3.16.4 Setting Liquid Level with Fisher 2500 Controller 3.16.5 Setting Liquid Level with Fisher 2900 Controller 3.13.6 Diverting Flow via Liquid Meters

3.16.7 Reading Barton Recorder 3.16.8 Using Sight Glasses 3.16.9 Meter Factors 3.16.10 Shrinkage Factors 3.17 Gas Diverter Manifolds

3.17.1 Operating Guidelines 3.17.2 To Switch Flares 3.18 Oil Diverter Manifolds

3.18.1 Oil Flow from Separator to Burner 3.18.2 Oil Flow to Gauge/Surge Tank

3.18.3 Oil Manifold Operation to Pump Out Tank to Burner 3.19 Surge/Gauge Tanks

3.19.1 Start-Up and Gauging Flow

3.19.3 To Switch Sides on both Surge and Gauge Tanks 3.19.4 To Pump Out one or both Components

3.22 Burners

3.22.1 Supergreen Crude Oil Burner Maintenance Guidelines 3.23 Pressurised Laboratories

3.24 Ancillary Equipment

3.24.1 Deadweight Testers

3.24.2 Pressure/Temperature Recorders 3.24.3 Chemical Injection Pumps 3.24.4 Ranarex Gravitometer 3.24.5 Ultrasonic Thickness Gauges 3.24.6 Fisher 67FR Air Regulators 3.24.7 Pressure Gauges 3.24.8 Stick Thermometers 3.25 Valves 3.25.1 McEvoy 3.25.2 Foley 3.25.3 Magnum Converted 3.26 Third Party Equipment

3.26.1 Compressors 3.26.2 Steam Generators 3.27 Proppant Knockout Vessel

3.27.1 Initial Job Start Up

3.27.2 End of Test Clean Out Procedures TABLES

3-1 Required Number of Turns to Fully Open/Close a McEvoy Valve 3-2 Rislan Hoses

3-3 Coflon Hoses

3-4 List of Hoses in Service

3-5 Minimum Allowable Wall Thickness for A106B Steel 3-6 Thickness Checking

3-7 Typical Range of Unions Used by EXPRO 3-8 API Rated Flange Pressure Ratings 3-9 ASA Rated Flange Pressure Ratings

3-10 Pipeline Capacities (mmscf/d) from High Pressure Relief Valves 3-11 Pipeline Capacities (mmscf/d) from Heat Exchanger

3-12 Pipeline Capacities (mmscf/d) from Separator 3-13 Pipeline Capacities (mmscf/d) from Surge Tank 3-14 Pressure Ratings of Gauge

3-15 Required Number of Turns to Fully Open/Close a McEvoy Valve APPENDIX 3

Fig. 3.1 Actuator Lock-Open Cap and Disc Fig. 3.2 Pressure Pilot and Remote ESD Tie-in Fig. 3.3 Handling Coflexip Hoses

Fig. 3.4 Preferred Hook-up on Semi-submersible Rigs Fig. 3.5 Pipework Metal Band

Fig. 3.6 Barton Recorder Hook-up Fig. 3.7 Sample Points

Fig. 3.8 Clean-up Choke Manifolds Fig. 3.9 Separator Barton Hook-up Fig. 3.10 Gas Diverter Hook-up Fig. 3.11 Oil Manifold Hook-up

Fig. 3.12 Correct Installation of Dogs on Lines Fig. 3.13 Enclosure Layout

Fig. 3.14 Rotational Direction of Impeller Fig. 3.15 Typical Coflexip Hose Structure Fig. 3.16 Hammer Union Mating Parts Fig. 3.17 Clamp Connector Components Fig. 3.18 Data Headers

Fig. 3.19 Flange Make-up Sequence Fig. 3.20 Single Block Choke Manifolds Fig. 3.21 Double Block Choke Manifolds Fig. 3.22 Masterflo Micrometer Indicator Fig. 3.23 Daniel Senior Orifice Meter

Fig. 3.25 Liquid Meters Set-up Fig. 3.26 Shrinkage Tester Fig. 3.27 Gas Diverter Manifold Fig. 3.28 Oil Diverter Manifold

Fig. 3.29 Winding Teflon Tape on a Thread APPENDIX 3A

Fig 1- EXPRO 2" Supergreen Atomiser head Assembly - TED090101 Fig 2- EXPRO Lodge Ignition System (High Velocity) - TED080703 Fig 3- Typical Supergreen Burner Rig Up - TED090108

Fig 4- Fan Type Radiation Screen - TED080601

4.0 SURFACE SAMPLING GUIDELINES 4.1 PVT Sampling

4.2 Measuring Gas S.G. 4.3 Measuring Liquid S.G. 4.4 Measuring BS&W

4.5 Measuring Salinity (Chlorides) 4.6 Measuring Viscosity

4.7 Measuring Cloud/Pour Point 4.8 Measuring Resitivity of Water 4.9 Using Draeger Tester APPENDIX 4

Fig. 4.1 Gas PVT Sampling Hook-up Fig. 4.2 Oil PVT Sampling Hook-up Fig. 4.3 Atmospheric Sampling Fig. 4.4 Hydrometer in Cylinder Fig. 4.5 Use of Draeger Tester Fig. 4.6 Inserting Draeger Tubes 5.0 SAFETY GUIDELINES

5.1 General Safety 5.1.1 General 5.1.2 Emergency 5.2 Hook-up and Rig Down

5.2.1 Hook-up 5.2.2 Rig Down 5.3 Pressure Testing 5.4 Surface Sampling

5.5 Safety of Personnel While Working on Burner Booms 5.6 Corrosive and Hazardous Substances

6.0 CONTINGENCY GUIDELINES 6.1 Equipment Failure 6.2 Hydrates

6.3 Leaks

6.4 Suspension of Operations Due to Bad Weather 6.4.1 On Semi-Submersible Rigs

6.4.2 On All Rigs 6.5 High Temperatures 6.6 Miscellaneous

6.6.1 Contingency Procedures 6.6.2 Surface Data Logger 6.6.3 Data Points

6.7 Leaking Daniels Senior Orifice Meter

6.8 H2S Leak

6.9 Choke Manifold TABLES

7.0 MULTI SENSOR RELIEF VALVE (MSRV) 7.1 Specifications and Features

7.1.1 MSRV Safety Head Drawing 7.1.2 MSRV Drawing

7.2 Dis-Assembly Procedures 7.3 Assembly Procedures 7.4 Parts List

7.5 Pressure and Function Tests Maintenance Level 1

7.5.1 Impulse System Pressure Test 7.5.2 Internal Body Test

7.5.3 Closed Ball Valve Pressure Test 7.5.4 Ball Valve Gas Leak Test

7.5.5 Seat Leakage Criteria as per API 527 Maintenance Level 2

7.5.6 Impulse System Pressure Test 7.5.7 Internal Body Test

7.5.8 Closed Ball Valve Pressure/Function Test 7.5.9 Ball Valve Gas Leak Test

7.5.10 Seat Leakage Criteria as per API 527 7.6 Onshore - Maintenance Level 3

7.6.1 Impulse System Pressure Tests 7.6.2 Internal Body Test

7.6.3 Ball Valve Pressure/Function Test 7.6.4 Ball Valve - Gas Leak Test Seat Leakage Criteria as per API 527 Post Operations Function Test 7.7 Installation and Testing of Rupture Disc

7.7.1 Onsite Testing - Rupture Disc Installed 7.8 Operations with Emergency Shutdown System

7.8.1 Installation 7.8.2 Operation Principle 7.9 Contingency Procedures

7.9.1 Onsite Pressure Testing - Valve Leaks 7.9.2 Well Operations - Valve Activated APPENDIX 7

Fig 7.1 10K MSRV Job Card Fig 7.2 MSRV Spare Parts List Fig 7.3 Drawing Index

Fig 7.3.1 MSRV General Assembly TED180101

Fig 7.3.2 MSRV Sensor System Application (Standard) TED180121

Fig 7.3.3 MSRV Downstream Sensor Installation (Heater to Separator) TED180126 Fig 7.4 Document Change Request Form - AB/AD/0501Rev2

1.0

RISK ASSESSMENT

General hazards are identified in the Expro Group Safety Audit Procedure. This procedure detail the specific assessments made for operations.

Specific assessments for manual handling and display screen equipment are contained in their relevant procedures.

1.0.1 RESPONSIBILITIES

Base Managers are responsible for risk assessment being made in the areas they control.

Senior crew members are responsible for carrying out on the spot risk assessments for all operational activities that are considered to be outside the scope of a normal well test/wireline operation. All "on the spot" assessments will be approved/authorised by senior base management prior to work commencement.

The Safety department will support the Manager in making the assessment. Staff are responsible to co-operate with the assessments.

1.0.2 DEFINITIONS

1. Risk Assessment

A risk assessment consists essentially of an identification of the hazards present in an operation and an estimate of the extent of the risks involved, taking into account whatever precautions are already being taken.

2. Hazard

A hazard is an incident with the potential to cause harm.

3. Risk

Risk is the likelihood of the potential hazard being realised.

1.0.3 PROCEDURE

The Base manager ensures a list of all hazards is prepared.

An initial assessment of the risk from the hazards is then made using the Expro risk assessment form - see Appendix 1.

The detail required in the assessment report will vary greatly, depending upon the nature of the particular hazard identified.

In carrying out this exercise a 'risk rating' number has been arrived at, this is achieved in the following manner. Establish a probable frequency rating. To do this use the following scale:

1. A highly improbable frequency occurrence. 2. A remotely possible but known occurrence. 3. An occasional occurrence.

4. A fairly frequent occurrence. 5. A frequent and regular occurrence.

Now establish a potential severity rating for the identified hazard using the following scale: 1. Negligible Injuries.

1.0

RISK ASSESSMENT

Compile a risk rating number, using the table (see below) multiply the numbers derived from steps above. The risk rating enables the most serious hazard (those with the highest risk rating number) to be considered first.

NOTE: The scales listed above are included on the reverse side of the Risk Assessment Form.

SEVERITY 6 5 4 3 2 1 5 4 3 2 1 30 24 18 12 6 25 20 15 10 5 20 16 12 8 4 15 12 9 6 3 10 8 6 4 2 5 4 3 2 1 1.0.4 RISK RATINGS

Activities with a risk rating of 0-6 would generally be regarded as no further action required. The assessment may also adequately cover a number of straightforward hazards.

Activities with a risk rating of 7-15 will require an individual risk assessment being carried out detailing: - The nature of the hazard

- The degree of risk from the hazard - The people affected

- The precautions taken

- The information and training required.

Activities with a risk rating of 15-30 will require a very detailed risk assessment and where necessary, a detailed written safe system of work, which must identify all actions required to control the hazard.

1.0.5 ACTIONS

Actions should where possible, aim to prevent the risk at source by making machinery or operations safer, or to control the risk by developing safe system of work, or as a last resort, providing personnel protection.

Staff must be provided with relevant information and training on risks, preventative and protective measures, and emergency arrangements.

There are a number of established safety procedures in this manual to help with these assessments.

Where existing procedures do not cover the required assessment and the base manager decides he is unable to make a comprehensive assessment, then the safety department is available for assistance.

1.0.6 RECORDS

1.0

RISK ASSESSMENT

1.0.7 UPDATING RISK ASSESSMENTS Risk assessments are revised:

- When there are changes to equipment or in operations - Following accident and dangerous occurrences - When safety/quality audits identify new hazards

It is the responsibility of the base manager to ensure that an annual review is made of hazards and risk assessments.

Copies of revised risk assessments will be sent to the manager quality assurance & safety, who will be responsible for the re-distribution of the assessments to all group locations.

1.1

PRE-TEST PLANNING

This involves many departments from operations, engineering, materials, quality assurance and maintenance to provide suitable equipment to be shipped for a well test.

The sequence of events prior to a test will generally be as follows:-1. EXPRO awarded contract for well testing work.

2. Meetings between EXPRO and the client will be carried out as required, throughout the term of the contract, to ensure the smooth running of operations to the clients’ satisfaction.

3. Rig visit will be carried out if files on rig not up-to-date or if the well test will be of a non-standard nature. 4. Operating company calls for equipment for a forthcoming well test. EXPRO will organise third party equipment

to be used on test e.g. steam generators etc.

5. The relevant operations supervisor / manager is responsible for producing proposed layout and P.I. / flow diagrams for certification.

NOTE: Equipment Selection;

All components and equipment to be used on exploration wells which shall be exposed to a combination of pressure and hydrocarbons must be suitable for sour service to the material

requirements as defined in NACE MR-01-75.

In certain cases a Hazop study will have been attended. All relief lines, safety devices etc. will have been sized to expected well parameters (provided by operating company).

6. Routine maintenance is carried out on all equipment to maintain a pool of equipment ready to be shipped offshore at short notice. Specific equipment will be assigned to the particular well test and a certification package compiled, which will include the diagrams and information such as chemical data sheets. This package will be submitted for approval by the relevant certifying authority.

NOTE:

Release notes for equipment may be issued by the rig certifying authority e.g. DNV. These may be issued where the certifying body is not willing to certify some equipment for a year, but are willing to certify it for one job e.g. if not sure that pipework is H2S rated then it may be certified for a 'sweet' test and have hardness checks etc. carried out before the full certification is accorded.

7. A pre-test meeting may take place involving the well test supervisor or equivalent.

8. When equipment is required it will be shipped to rig (this will often be around the time when the liner / casing string is set).

NOTE:

Consideration will obviously have to be given to distances that the equipment must be transported, and the length of time it will take. It may be the case that the equipment will have been shipped before the logs have been viewed resulting in a change of equipment required or possibly, in the case of a dry hole, the de-mobilisation of the equipment.

9. Operating company will call for well test personnel.

1.1

PRE-TEST PLANNING

POINTS DISCUSSED IN MORE DETAIL

1.1.1 RIG VISIT

Once it has been decided that a well test will take place on a rig (or platform) then a rig visit will take place. This rig visit is to obtain at first hand information required for the success of a well testing programme and to overcome any problems in the planning stage, thus preventing possible delays at a more critical stage. The well tester carrying out the rig visit is expected to carry out the

following:-1. Initially make contact with operating and drilling company representatives to discuss the well testing program to take place.

2. To establish the equipment required to carry out that programme.

3. Establish where the equipment will be sited in relation to safe access and exit, and the relative proximity of hazardous areas for that particular installation.

NOTE: The safe routing of flowlines should also be considered.

4. Survey the flare boom installation i.e. take measurements required to hang booms and note any problems.

From the information gained on the rig visit a proposed layout diagram, boom loading diagram and/or a flow diagram/process and instrumentation diagram will be produced for certification by the rig certifying authority. Prior to producing these diagrams, Engineering will have carried out a study into the required size of relief lines and what safety devices should be installed and include these on the relevant diagrams. A copy will also be passed to the operating and drilling companies for their approval.

A file will be established for the rig for future reference and will be updated if future visits are carried out.

1.1.2 ENGINEERING REQUIREMENTS

1. To size relief valves, lines, safety devices, etc. to reduce process pressure below the equipment MAWP and to ensure that all pipework and equipment will remain within specification, in a worst case scenario.

2. To produce required diagrams for operating company, which may be of the following:-Equipment Layout Diagram

This diagram's main purpose is to highlight the rig's hazardous areas (around vents, electrical supply points etc.) and add the hazardous areas around the well test equipment. This diagram will be submitted for approval to the rigs certifying body before the well test to ensure no safety regulations are infringed in the spotting of equipment.

NOTE: This drawing is for a proposed equipment layout, if for any reason, the equipment is relocated, it is the rig owner’s responsibility to inform the certifying authority.

1.1

PRE-TEST PLANNING

Equipment Process and Instrumentation Diagram (P and I.D.)

This diagram shows the process flow and the instrumentation and safety devices attached to the well test equipment. These diagrams also have to be approved by the rigs certifying body.

These diagrams are standardised but can be altered for specific well tests once the clients’ equipment requirements are known.

There are also other constraints to be considered prior to the completion of these diagrams, in that when working offshore the available deck space will play a major part in determining where, exactly, the larger items of equipment are placed.

Consideration should also be given to the layout of flowlines in order to reduce the amount of elbows and restrictions thus reducing turbulence and any pressure drop through the flowline.

Flow Diagram

This diagram is an elementary P and I.D. and shows the flow path through the well test equipment, with valve configuration and will include safety devices.

The Engineering department will also attend HAZOP studies if required.

1.1.3 HAZOP STUDIES

These are discussions to look at potential hazards of operations on a WHAT IF basis. i.e. if this happens what will be the result.

They are attended by all the companies involved in well operations i.e. the operating, drilling and all service companies. A third party may also attend these discussions to put forth an independent point of view to promote discussion.

Operations will be broken down into blocks and looked at in detail e.g. what are the consequences of opening this valve, could it create a hazard. This will be carried out for the complete process train of the proposed well programme.

1.1.4 EQUIPMENT MAINTENANCE

Routine maintenance procedures have been drawn up which are carried out on all equipment prior to shipping for a well test.

Generally this maintenance will include the following: -a) Visually inspected

b) Internal inspected where applicable

c) Thickness checked where applicable (when abrasive materials have been flowed through the equipment or when a survey is required eg. a major survey).

d) Pressure tested

e) Non-routine repairs carried out as required

f) Paint and corrosion protection applied as per EXPRO maintenance procedures. g) Slings inspected

1.1

PRE-TEST PLANNING

Certification is carried out on all equipment and is done on a 5 yearly (major) and yearly (annual) basis. The annual surveys include a visual inspection and pressure test to full working pressure to check the continuing functional ability of the equipment and any other requirements of the individual certifying authority.

NOTE: Before annual certification is issued the certifying authority must be satisfied as to the routine maintenance program carried out on the equipment throughout the year (which is recorded on maintenance records for each item of equipment).

Major surveys include all the features of an annual survey but generally speaking pressure tests are to 1-1/2 times maximum working pressure and the surveys may also include whatever the surveyor deems necessary eg. hardness checks etc., dependant on the equipment's service history.

It should be noted that annual surveys have a 3-month period of grace after the 12 month period to allow for equipment which is offshore on a long term contract, where certification may run out, to continue to be used for the short term. If the contract is ongoing after the 3-month period of grace then the equipment must be changed out and re-certified. If the equipment is not certified within the 3-month period (eg. due to transportation delays) then it must have a full major survey carried out before it will be re-certified.

This 3 month period is not intended to allow for equipment to be sent offshore, short term, after the certification has run out.

1.1.6 PRE-TEST MEETINGS

These are usually held shortly before the actual start date of operations and involve the operating and drilling companies, and all the service companies who will carry out the operations during the course of the well test. From EXPRO's point of view these meetings are normally attended by the supervisor who will carry out the test. The purpose of these meetings is to run through the programme of operations and to discuss the safety aspects of these operations. It is also to interface the equipment requirements between the different service companies, to ensure that it is known who supplies what eg. the proper cross-overs etc.

The well test supervisor will take the proposed drawings produced by the engineering department to the meeting and will be ready to discuss the nature of operations from EXPRO's point of view eg. the safety aspects with regards to the well test equipment. He should also expect to answer specific questions related to our equipment and queries as to how the equipment works.

Another topic that may be discussed are environmental issues e.g. noise pollution, oil spills, black smoke, etc.

1.1.7 EQUIPMENT REQUIREMENTS

The operations supervisor will have been liasing with the client from the outset as to the equipment required. Together with the workshop foreman, he will assign it for that particular job and also deal with any special requirements eg., third party equipment to be used, or any particular EXPRO equipment to be used eg. D30 vertical separator (for high deliverability wells).

Once the equipment has been selected, it will be logged on the ECS computer system for that job to ensure that the whereabouts of all equipment is known at all times. The Materials / Transport department will complete the relevant dangerous goods notes and ensure that all paperwork is in order (not including certification which will be the responsibility of the Quality Assurance department).

The materials co-ordinator will also arrange for the transport of equipment to and from the required location of the client e.g. which docks etc., on the proper dates.

1.1

PRE-TEST PLANNING

1.1.8 PERSONNEL MOBILISATION

This will be carried out, in the numbers required, when requested by the operating company.

Personnel will be provided with all the required safety clothing to comply with EXPRO's company safety policy and COSHH regulations.

Generally once a test is known to be forthcoming personnel assigned to that job are placed on standby to go offshore. This requires that they regularly check with the office and leave contact numbers if they plan to be away from home, until told to stand down

1.2

PRE-TEST WORK SITE GUIDELINES

On arrival at the work site the EXPRO supervisor in charge of the job should follow the guidelines below to ensure that all runs smoothly during the forthcoming well test.

1. The Supervisor should introduce himself to the Company man / Drilling supervisor and discuss the test requirements. Also they should introduce themselves to any other people who may assist EXPRO during a well test, eg. the Barge Engineer, Crane Operator, etc.

2. The equipment should be inspected on arrival to the rig, for damage in transit, in order to maximise the time for EXPRO to respond. Particular attention should be placed on the availability of required instrumentation. 3. Work areas should be inspected to ensure equipment can be spotted as per the layout diagram, and escape

routes decided upon.

4. The separator should be checked, both for accessories (eg. orifice plates, etc.) and the operation of equipment.

a) Sight glasses are clear and allow liquid level to rise and fall. b) Dump valves stroke properly and travel correct distance.

c) Liquid meters should be checked that they are not seized, gearing should be checked, (meter factors will be performed later).

d) Check the float retainers are removed (if fitted) and floats are connected to displacer arms. 5. The spares inventory should be checked along with availability of correct cross-overs.

6. The chokes should be checked for a full set and any extras that may be required (eg. 1/64th increments during sand frac clean-ups).

7. Pressure recorders such as Foxboro or Barton should be calibration checked and recalibrated if required.

NOTE: In the field it is not practical to recalibrate the temperature probe, due to the complicated nature of this

process, but it should be checked with cold and hot sources to verify it's accuracy. Use a stick thermometer in the thermowell if the temperature probe is out of calibration.

8. Barton differential recorders should be calibration checked (both static and differential) and recalibrated if required. The correct plumbing of the Barton should also be checked (flange taps and upstream static pressure).

9. The Data Logger / Edge system pressure transducers should be calibration checked and the correct functioning of the system confirmed. The operator of the DAS must be made aware of the expected well parameters, threshold values, etc.

10. The heat exchanger if used (should be pre-heated to the required temperature, and the operation of the temperature controller checked.

11. The supervisor should ensure that all EXPRO crew members are aware of the rig alarm system (audible and visual) and understand what each alarm is.

12. The supervisor should also ensure that senior crew members have a knowledge of the permit-to-work system that work will be carried out under.

13. Where required, the supervisor should ensure that all crew members know where safety equipment eg. B.A. sets etc. are located and ensure that all EXPRO crew know the escape routes and muster points.

14. Paperwork and stationary supplies / computer and computer supplies (if used) should be checked to ensure that there is a plentiful supply and that the computer has not been damaged in transit.

1.3

RIG VISITS

A rig visit should be performed if a test is to be carried out on a rig that EXPRO have not tested on before or have not tested on for some time.

The purpose of this rig visit is to ensure that equipment can be spotted without problems, that tie in points to rig lines, etc. and whatever crossovers required are identified. It is also a time to meet with operating and drilling company representatives and to check out rig certification, e.g. of permanent piping, etc.

The rig visit checklist should be completed (Refer to Fig. 1.5 for an example) as much as possible. This will enable base staff to plan equipment/flowline, etc. requirements.

NOTE: The completed rig visit checklist forms part of the planning report that is submitted for Certifying Authority approval.

1.4

GAS WELL TESTING

1. LIQUID LOADING

This problem usually occurs when testing low producing gas wells with high liquid-gas ratios. Indications of liquid loading are wide variations of surface pressures.

2. HYDRATE FORMATION

This problem occurs normally in a high-pressure gas well.

Flow across chokes or separator back pressure valve may also plug off causing upstream pressure to rise.

Chemicals such as glycol and methanol can be injected (upstream of any potentially large pressure drops) to prevent and inhibit hydrate formation.

However if a heat exchanger is used, this problem can largely be eliminated by maintaining the well stream temperature above the hydrate formation temperature.

3. WET GAS STREAMS

Wet gas streams can cause inaccuracies when measuring the specific gravity of a gas. They also can cause instrument lines to 'freeze' in extreme cold climates if running off separator gas instead of air, differential recorders can 'freeze' also.

Knock-out pots, possibly filled with steel wool or with wire mesh screens to assist liquid knockout from gas, can be used to overcome this. These pots must be blown down regularly.

4. IRREGULAR FLOW

A frequent difficulty encountered in measuring accurately, gas flow rates is the rapidly changing rate when a well 'slugs'.

This type of flow can cause errors when reading differential recorder charts but can be partially overcome by increasing the proportional band setting on the back pressure controller (this will cause the BPV to stroke at less sensitive pressure changes and stop 'hunting'). Also the pulsation dampening screw on the DPU cell can be screwed in restricting the flow of oil between either side of the bellows. (Do not screw in more than 1 1/2 turns from fully closed or else no pen movement may be observed).

The pulsation dampener can be found under the screw at the back of the DPU cell (model 199) and requires a 1/8" sized Allen Key to adjust.

Clockwise adjustment reduces pulsation, anti-clockwise increases. 5. SOUR (H2S) GAS

Sour gas is extremely toxic, causing illness and death in relatively small atmospheric quantities. H2S procedures are fully covered under Section 1.9.

1.4

GAS WELL TESTING

The actual course of events may differ according to conditions on the rig at the actual time of operations and the clients Test Programme.

ASSUMPTIONS

a) SAFE and Coiled Tubing Cutting valves (if either used) installed and function tested. b) Surface Test Tree installed with kill-wing and swab valves closed and master valve open. c) All down hole safety valve(s) open.

d) Texteam pump function tested, and methanol available in sufficient quantity.

STABILISED CONDITIONS attained

when:-a) For closed in periods build-up <= 1 psi per 30 minutes. b) For flowing

periods:-c) BS&W < 7% (or < 5% if mud present).

d) Pressure does not vary more than 0.1% of C/I pressure during 15 minute period. e) Gas and liquid rates are constant.

1. Pressure test well test equipment as per client's programme. 2. Function test ESD system remote stations and high pressure pilot. 3. Check calibration of Barton / Foxboro recorders with poddy meter.

4. Function Test burner water injection screen and ignition systems. Function test burners with diesel if environmentally acceptable.

5. Open choke manifold downstream valve.

6. Line up gas diverter manifold to boom with favourable wind conditions and ensure standby boom is isolated at diverter manifold.

7. Ensure system is set up via separator bypass to flow to flare, this will prevent damage or plugging of liquid meters and settling of solids or mud in separator during clean-up.

8. Ignite propane / diesel pilot burner in readiness for gas returns. 9. Apply radiation water screen to burner head.

10. Open well to overboard on suitable adjustable choke.

NOTE: On dual train systems, secondary train should be opened early in the flow period to clear system of any trapped liquids while gas velocities are still relatively low. This will reduce reactive forces caused should a slug of water be introduced into a high velocity gas stream.

11. Monitor surface pressures / temperatures and nature of produced fluids.

Take Draeger tests for H2S, CO2 and N2 when first gas at surface (test for mercaptans can also be carried out). Continue testing every 3 hours or as required.

1.4

GAS WELL TESTING

12. Gradually bean up in required choke increments and flow until well clean and desired drawdown / flowrate is achieved under stable conditions.

a) Estimate gas flow rates on each choke setting prior to beaning up.

b) During Clean-Up, as a minimum, it is necessary to produce a volume of fluids at least equal to the volume of the well bore.

c) Generally the well will be cleaned up to a rate equal to or greater than the highest rate that the well will be tested to.

NOTE: At end of clean-up period it may be required to flow via test separator to obtain accurate flow data. Liquid levels may be established if separator used at this stage.

13. Close in at choke manifold or downhole tester valve for pressure build-up to record initial reservoir pressure and temperature. This pressure is necessary to calculate the A.O.F. or deliverability plots. 14. Once stable C/I conditions reached open well at choke manifold and flow well for one or more

successive flow rates.

These flow rates will generally be of sequence smallest choke bean to largest.

a) The minimum flow rate should produce a pressure drop approximately 5% of shut-in pressure, or at least to the size required to lift liquids, if any, from the well.

b) The maximum flow rate should produce a pressure drop of approximately 25% of shut-in pressure.

c) Any other flow rates should fall equally between these constraints.

NOTE: Drawdown of the well should not > 50% of shut-in pressure to prevent possible damage to the well-bore.

15. Flow via separator for required flow period, collecting desired samples (PVT, bulk etc.) as required for each flow rate.

Each rate must be flowed to stabilisation in order to obtain correct data to calculate A.O.F. or deliverability plots and prevent need for a retest.

If flowing for several flow rates work out, during initial shut-in, if one orifice plate can cover all flow rates (while maintaining > 20% and < 80% of differential range). If not, use minimum orifice plate changes as possible.

16. Close in well at choke manifold (or down-hole tester valve) and observe pressure build-up until initial reservoir pressure achieved.

1.5

OIL WELL TESTING

1. EMULSIONS

If the fluid from a well consists of both oil and water, there is a possibility that they will not separate. The resulting fluid is commonly called an emulsion. If this emulsion is measured as oil, the test will be in error by the amount of water in the emulsion.

2. FOAMING OIL

When the pressure is reduced on certain types of crude oils, foam (or froth) can be caused by the liberation of a large amount of micro bubbles in the oil, as the gas comes out of solution, where these bubbles are encased in a thin film of oil. In other types of crude oil the viscosity and surface tension of the oil may mechanically lock gas in the oil and cause an effect similar to foam.

The presence of foaming oil can lead to a number of problems if not treated such as: -a) Prevent good separation and reduce separator capacity.

b) Disrupt liquid and gas metering c) Disrupt pumping operations d) Cause potential burning problems

Foaming oil procedures are fully covered under section 1.8. 3. PARAFFINS

Paraffin deposition in separators reduces their efficiency and may render them inoperable by partially filling the vessel and / or blocking the mist extractor and fluid passages.

These deposits can be effectively removed from separators through the use of steam or chemicals.

4. SAND, MUD, SALT ETC.

If sand or other solids are continuously produced in appreciable quantities with well fluids, they must be removed as soon as possible from the well stream. If not, deposits may build-up on vessel interiors, reducing capacity and operating efficiency.

Where well pressures allow, the EXPRO twin pot sandfilter assembly can be used to remove these solids, (for further information on sandfilters refer to Section 3.11).

5. SOUR (H2S) OIL WELLS

Sour oil wells cause the same problems as a sour gas well as the H2S gas produced with the oil is extremely toxic, causing illness and death in relatively small atmospheric quantities

1.6

SOLIDS MANAGEMENT

Solids production is becoming more and more of a problem for the oil industry with depleting reservoirs and rising solids production. Solids handling equipment is therefore becoming increasingly important due to financial, environmental and safety consequences.

Solids can be produced either:

In a controlled manner using specially designed dedicated equipment. 1. Sand Filters/Wellhead Desander

For more details refer to the following operational guideline sections; chapter 1 General operating guidelines

Section 1.6 Sand “frac clean ups” chapter 3 Section 3.11 Sand filters

2. Sand Monitoring Equipment

These instruments basically monitor sand production accurately and if sand production is getting above an acceptable level the flow has to be reduced, causing the solids production to decrease simultaneously.

There is a whole range of detection devices available however we can divide them into two different systems. 2.1 Non Intrusive Detectors

They work on the principle of detecting the acoustic noise of sand particle impacts on the outside of pipe bends. The three main suppliers of this technology are:

Fluenta Clampon Stress wave Devices

2.2 The intrusive probes work on the principle of measuring the increase in electrical resistance of a metallic element exposed to erosion by the sand flow. Intrusive type probes are not used anymore within The Expro Group.

3. Uncontrolled sand production

With no sand control equipment available sand production can only be detected with: BSW measurements

Choke erosion

Malfunctioning instrumentation Sudden leaks due to erosion

BSW

BSW = Basic Sediment and Water

BSW measurements should be taken at regular intervals and normally give the first indication of solids being produced. After the spin out the solids are collected at the bottom of the sample tube where the amount can be measured.

1.6

SOLIDS MANAGEMENT

Reference the following operational guideline sections; Chapter 6 Contingency guidelines

Section 6.9 Choke manifold

5 Malfunctioning Instrumentation

The first signals of having solids produced and accumulating in the system is normally the performance of the separator. With the bottom part of the interface sight glass plugged off it will be impossible to find a true interface. Other sensitive areas for solids production are;

Plugged liners from DWT, BARTON, FOXBORO and EDGE sensors. Plugged gauges reflecting a wrong pressure.

Faulty readings from the level controllers. Plugged sight glasses.

Bad separation due to reduced volume in separator.

In general the process would not be under full control due to wrong information given by the instrumentation. Eventually this could lead to an ESD signal, carry over or gas blow-by to the tanks.

Ifone of the above happens be aware of solids production

.

6 Sudden Leaks

If solids are produced without being detected unexpected leaks could occur In general at places where a pressure drop takes place or where turbulence is created.

In or just after elbows or bents After X-covers

Near swages

In general after a pressure drop

Other notorious places for sudden leaks due to solids erosion are; Liquid control valves (dump valves of the separator)

Back pressure valves (due to the pressure drop) On threaded unions (due to turbulence)

Despite wall thickness measurements being taken at regular intervals a sudden leakage could occur at any time. This leak could be potentially dangerous for well test personnel, high velocity escaping gas containing solids could be experienced causing severe injuries.

If a sudden leak occurs close in the well as quick as possible using the Emergency Shut Down system. The ESD buttons are located at strategic places around the test facility and in safe areas.

Leaks caused by erosion are known to increase very rapidly and could be completely out of control in minutes. After the complete package is bled off start with inspection of the most sensitive points,

- Pipework downstream choke manifold - heater inlet elbow

- heater outlet elbow - heater coil elbows - separator inlet spool piece - downstream back pressure valves - All sensor lines and instrumentation. - DWT

- Foxboro

- All EDGE sensors - Separator BARTON

- All instrumentation manifolds and gauges - Vessels and tanks

- All liquid drains - External float chambers

1.6

SOLIDS MANAGEMENT

The minimum inspection should consist out of a wall thickness survey and where possible a visual inspection. List the equipment used accurately for later traceability.

Produced solids normally accumulate in the following places. In the sand filter or well head desander

In pressurised vessels In tanks

In dead ends of the process system a Sand filters or Well head desander

This equipment is specially designed to remove the solids from the well stream.

For detailed description refer chapter 3, section 3.11 Sand filters, of the well test operational guidelines.

b Vessels

This could be any vessel in the test package; First stage separator

Second stage separator Knockout vessel

c Tanks

This could be any tank used in the process system;

Of course the solids accumulate at the bottom but could also in certain circumstances accumulate on the wall of a tank causing serious mis-readings.

Surge tank Gauge tank Storage tank

d Dead ends in the process system This could be in the following cases

Heater bypass valve and inlet valve open and the outlet valve closed. This is bad practice and should not be done. However if this is the case solids could accumulate in the heater coil.

With complicated rig ups sometimes solids accumulate near bypass valves where there is no flow. Obviously these situations must be avoided at all times.

Reference the next chapters in the well test operational guidelines; chapter 1 General operating guidelines

section 1.6 sand “frac clean ups” section 1.10 acid clean up procedures chapter 3 Equipment operating guidelines

section 3.27 proppant knockout vessel chapter 4 Surface sampling guidelines

section 4.4 measuring BS&W chapter 5 Safety guidelines

1.6

SOLIDS MANAGEMENT

Solids are considered to be:

Any slurry / sludge / solids, consisting out of and a combination of Any type of formation sand in any size.

Artificial made proppant in any size. Pipe dope.

Scale from tubing/casing. Metal parts from perforating guns. Metal parts from milling operations.

Rubber parts from previous well intervention work. Rocks or stones from the formation.

Spent acid slurry.

Lost circulation materials like; Carbonates

Coconut chips Chicken grid Cement parts

Basically any combination which can be produced by the formation or what can be pumped into the well. Depending on the specific situation solids are contaminated and therefore be very dangerous for the health of the operator coming in contact with the solids. Appropriate safety measurements have to be taken in order to perform the work safely. Refer Health and Safety Manual System No. 0701 and the operational guidelines section 5 sub section 5.6.

Solids could be contaminated with; ACID / SPENT ACID

BENZENE / TOLUENE VAPOURS INJECTED INHIBITOR

LSA

H2S VAPOURS MERCURY VAPOURS METAL DEBRIS

OTHER TOXIC MATERIAL INJECTED OXY SCAVENGER

BIOCIDE TOXIC POLYMER RADIOACTIVE TRACER SCALES

a. ACID / SPENT ACID

For stimulation purposes a whole variety of acid is pumped into the well either bull-headed or using coiled tubing. After the acid operations the well should flow again. At this time acid either pure or spent is produced back to surface again.

The required precautions are mentioned in the well test operational guidelines chapter 1 section 1.10 Acid clean up procedures.

After the job the solids and or sludge/slurry can be found in the vessels and the tanks. All safety measures must be taken as per Health and Safety Manual System No. 0803

b. BENZENE / TOLUENE VAPOURS

Oil residue normally contains benzene and or toluene vapours, particular gas wells are notorious for this. These vapours are very toxic and even once the vessels and tanks are completely bled off slurry/sludge will produce the vapours for a long time.

All safety measurements must be taken as per Health and Safety Manual System No. 0701 and System No. 0801 / 0802

1.6

SOLIDS MANAGEMENT

c. INHIBITOR INJECTED INTO THE TUBING

Inhibitor is normally injected into the tubing through an injection valve down hole and is meant to extend the lifetime of the tubing drastically. In general these liquids are very abrasive and should never be touched with bare hands and without BA. The chemical data sheets of the used inhibitor must be available at all times.

All safety measurements must be taken as per Health and Safety Manual System No. 0801

d. LSA FORMATION SAND

Especially older gas fields start producing LSA contaminated formation solids. LSA stands for

Light Super Altitude

Great care should be taken since you won’t notice a direct effect but the long term effects are severe.

On locations known to produce LSA solids a level 3 inspector should be available at all times. Accumulation of LSA material in your body does finally cause death. For the correct safety procedure see the attached manual. All safety measurements must be taken as per Health and Safety Manual System No. 0805

e. H2S VAPOURS

From an oil residue H2S could escape for a long time. H2S is also known to penetrate metal and slowly escape from within the metal after it is taken out of the H2S environment. This process, depending on the concentration, could last for weeks. The vapours are very toxic and have a very low MAC value. Once the vessels and tanks are completely bled off, slurry/sludge remaining at the bottom will also produce the vapours for a long time. All safety measurements must be taken as per Health and Safety Manual System No. 0802

f. MERCURY VAPOURS

Some gas and oil fields are known to produce mercury. Initially the amounts are small but after accumulation pure mercury will be present in vessels and tanks.

For the correct safety procedure see the attached manual.

All safety measurements must be taken as per Health and Safety Manual System No. 0803

g. METAL DEBRIS

After perforating a well guns debris is normally produced to surface.

Depending on the type of gun used, sharp metal pieces will come to surface and will cause damage to the valves and instrumentation. Normally the debris will plug up the adjustable choke causing interrupting the initial clean up period due to choke changes and other complications. Because the debris is from metal the damage to valves and instrumentation could be severe and must be avoided whenever possible.

All safety measurements must be taken as per Health and Safety Manual System No. 0701

h. OTHER TOXIC MATERIAL INJECTED OXY SCAVENGER` BIOCIDE

TOXIC POLYMER

Water injection wells are sometimes injected with the mentioned liquids and therefore whenever working on water injection well be aware of this and have the chemical data cards available on site.

1.6

SOLIDS MANAGEMENT

In the past wells have been stimulated with radioactive proppant to measure the performance of the hydraulic sand frac. Nowadays for obvious reasons this is not performed anymore.

However producing a well which is fracced with radioactive proppant in the past still could produce, even after years radioactive proppant.

The same safety precautions should be taken as with an LSA contaminated well. For the correct safety procedure see the attached manual.

All safety measurements must be taken as per Health and Safety Manual System No. 0805

j. SCALES

Throughout the well lifetime scales could accumulate on the inside of the tubing wall and finally either block the tubing or be produced to surface causing complications in the process.

1.6

SOLIDS MANAGEMENT

1.6.2

SAND “FRAC-CLEAN UPS”

INTRODUCTION

1. Sand Fracturing is a well established and proven method of increasing production from both oil and gas reservoirs. In recent years these operations have been particularly active in the gas fields of the Southern North Sea.

2. There are number of inherent problems associated with 'sand frac' operations, erosion being of a particular concern. During post-frac clean-up operations sand or proppant not retained in the fracture, along with spent gel, have to be removed prior to producing the well. The effect of this highly abrasive fluid on surface equipment is dramatic, causing extreme erosion within piping systems, especially downstream of chokes. 3. The EXPRO clean up package is a system designed to safely dispose of well effluents after massive sand

fracturing operations and minimise the damage to Well Test equipment. Clean up involving handling of frac. sands and broken gels is achieved using a custom designed overboard clean up line, whilst removal of solids is achieved in a highly specialised sand filtration package (ref OSP 4.09). This approach to clean up operations alleviates the need for large capacity gravity separation devices and their associated control and material handling problems and reduces the risk of gas escape due to washed out and cut out lines.

4. A major factor influencing system design relates to the control of velocities at all times in order to minimise erosion.

5. Hence, during clean up, well control is achieved by choking primarily at the choke manifold and secondly, at the burner booms thereby minimising velocity through all major flowlines. Due to the extremely erosive nature of this process, special care regarding piping design has been imperative. All efforts to minimise directional flow changes have been made, but as and when required the fittings used are of a design where risk of cut out is low, ie, flanged 90 targets, lateral tees. All pipe sizes have been kept to a maximum within practical limits. 6. On completion of the clean up period when production of frac. fluids/proppant is significantly reduced, filtered

gas can be directed to the production loop and test separator.

NOTE: The liquid capacity of the sand filter package is limited and is dependant on the sizing of the filter carriage viscosity of the liquid being handled.

7. The following recommendations have been obtained through several years of experience of Post Fracture Stimulation Clean Up Operations. These procedures have been accepted and adopted by most major oil companies. They provide the safest approach to a hazardous operation and for that reason should be given full consideration when preparing well test programmes.

OPERATING GUIDELINE

The following is indicative of the sequence of events and operating procedures to achieve a safe and effective clean up programme.

A fracture stimulated well must be flowed clean of fracturing fluids and proppant via sand filter equipment to minimise any damage to the clean up system. This should be undertaken in such a way as to achieve acceptable maximum gas flow rates in as short a period as possible without causing erosion of surface facilities or damaging the proppant pack in the near well bore vicinity.

Prior to starting clean up operations the fracture must be closed and the fracture fluids (gels) broken down and 'leaked off'. The proppant pack will have started developing as the fracture closes. However, during the early stages of clean up the proppant particles are adjusting and packing as a result of the closure stress exerted on the proppant.

It is recommended that initial clean up starts on, no bigger than, a 16/64ths fixed choke. (Coiled tubing/nitrogen lifting is normally required to bring the well into production by lifting fluids gradually whilst running in hole). Fluid production should be kept to a minimum as broken gel exerts drag on the proppant pack, therefore, if a small choke size is used back pressure against the formation will be maximised. It should be noted that pressure drop and velocity of the fluid, would both increase near the wellbore. As the well slowly starts

1.6

SOLIDS MANAGEMENT

SAND “FRAC-CLEAN UPS”

clean up the well head pressure will obviously increase, hence beaning up should not be undertaken until some sort of stability has been achieved.

It should be noted that proppant does not always come to surface straight away. Tubing size, deviation & flowing parameters, all need to be taken into account. Therefore, it is inadvisable to attempt to speed things up during the early stages as damage in the fracture will also effect the well's long term deliverability. By following a set procedure the proppant production can be controlled and handled safely by the filters and other

equipment. Damaged or crushed proppant is a result of large pressure drawdown and, therefore, high closure stress exerted on the proppant.

The actual course of events may differ according to conditions on the rig at the actual time of operations. ASSUMPTIONS

a) At the end of the fracture stimulation the test string was displaced to seawater (dependant on stimulation programme).

b) Kill wing on tree closed.

c) Master valve and down hole safety valves open.

d) A datum has been established with respect to pipe wall thicknesses.

1. Close swab valve.

2. Bleed down pressure in frac. line and rig down frac lines.

3. Close sand filter bypass and ensure filters installed of range suitable for coiled tubing operations. 4. Open choke manifold downstream valves (clean up line side).

5. Ensure heater inlet valve - test line side - closed and test system vented via oil line (see Note b.) 6. Line up gas diverter manifold to boom with favourable wind direction.

7. Ensure standby boom is isolated at gas manifold. 8. Ignite propane pilot burner.

9. Apply radiation water screen to burner head.

10. Open well to overboard flare via fixed choke (12/64ths to 16/64ths) at choke manifold and at adjustable choke box at boom.

11. Continually monitor surface pressures/temperatures and nature of produced fluids. 12. Bring on well slowly on 12/64ths to 16/64ths fixed choke.

13. Establish well production and retrieve coiled tubing when well is flowing satisfactorily, without nitrogen lift. S.G. of gas can be monitored from samples taken from top of sand filters.

14. (It should be noted that a pump rate of 500 scf/minute of nitrogen maximum should be pumped whilst running in hole to prevent the well being 'held' back due to excessive wellhead pressure (on the small choke size).

15. Liquid production should be controlled and observed (rough guideline: maximum 1 bbl/minute) and the rate estimated from the flare. Proppant production should be observed and an accurate proppant rate established.

THE TEST SEPARATOR AND PRODUCTION FACILITIES SHOULD NOT BE CONSIDERED DURING THE EARLY STAGES OF CLEAN UP (SEE SEPARATE GUIDELINES).

1.6

SOLIDS MANAGEMENT

SAND “FRAC-CLEAN UPS”

16. When the well head pressure shows signs of stability and measured proppant production (if any) over the last 3 hours is 50 lbs/hour or less bean up 1/64ths.

17. Continue bean up in this way until proppant is produced to surface or if proppant production exceeds 500 lbs/hour then bean back, unless a downward trend is obvious.

18. Monitor sand filter efficiency via optional sand probe and/or by checking choke box after choke changes.

19. Monitor pipe wall thicknesses regularly using an ultrasonic thickness meter (ref. OSP section 9.3.1). 20. If problems are encountered in maintaining a lighted flare (due to slugging or nature of produced

fluids, e.g. spent gel) leave pilot system running continuously or light a `lance' and place near end gas overboard line.

21. Once 28/64ths choke is reached consideration can be given to beaning up 2/64ths when proppant production is less than 50 lbs/hour over a 3 hour period.

22. Once 40/64ths choke is reached consideration can be given to beaning up 4/64ths when proppant production is less thank 50 lbs/hour over a 3 hour period.

a) When opening and closing gate valves, the number of turns achieved should be noted, so as to ascertain if a valve is 'sanding up', and therefore, not fully closing.

b) While flowing via the clean up line with test line isolated, ensure that the test line is open to atmosphere via the oil line to the burner not in use. This will ensure there is no pressure build up in the test lines if an isolation valve begins to pass.

c) Constantly observe both upstream and downstream choke pressures to ensure choke erosion does not go undetected. Visual choke / adaptor inspection should take place at least every 3 hours unless proppant production is insignificant.

d) Before attempting to flow via the test separator / production loop proppant production should be observed and a proppant rate established.

e) If a quick gas/water rate is required during the clean up the proppant production should be less than 30 lbs/hour over a 3 hour period with a downward trend.

Wellhead pressure should be stable (well not slugging). If two sets of filters are available use two in series in case of filter rupture. Flow via separator for 1 to 2 hours to obtain flow rate information then continue clean up via clean up system (check separator drain for proppant).

f) At the end of the clean up proppant production needs to be 2 lbs/hour or less with a downward trend over a 3 hour period before flowing for extended periods via the production loop. To achieve this bean back the well until flowing conditions are satisfactory. (4/64ths is usually enough). Use the smallest filter size possible without effecting the well performance and check the separator drain regularly for unfiltered proppant/fines.

Velocity through the test system should be considered at all times.

g) If for any reason the well is closed in during clean up it should be reopened with care. Bean up slowly from 16/64ths to give a maximum of 100 psi/hour drop in flowing tubing head pressure until close to previous flowing pressure / choke size. Check proppant production prior to final bean up to original choke size as well performance / characteristics may have changed due to shut in.

1.6

SOLIDS MANAGEMENT

SAND “FRAC-CLEAN UPS”

USE OF A SAND FILTER BYPASS LINE

1. A bypass line can be included in the clean up system to handle large volumes of proppant safely and efficiently during initial clean up and reversing out procedures.

2. However, once the well is flowing independently, it is advisable to bean back the well to reduce proppant production to a manageable level and divert the flow through the Sand Filters where the clean up can continue in a controlled manner. This also reduces the risk of erosion downstream of the boom choke.

3. The bypass line will consist of an 'L' shaped dual isolation manifold installed upstream of the Sand Filters and a separate line running to a boom with favourable wind direction. The line will include chemical injection / pressure tapping points and a choke box installed at the base of the boom to control flow back during coiled tubing nitrogen lift operations.

NOTE: a) The line will have been pressure tested to 5,000 psig prior to flowback.