Well test procedures manual

ARPO
ENI S.p.A.
Agip Division
ORGANISING
DEPARTMENT
TYPE OF
ACTIVITY'
ISSUING
DEPT.
DOC.
TYPE
REFER TO
SECTION N.
PAGE. 1
OF 108
STAP P 1 M 7130
The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for
reasons different from those owing to which it was given
TITLE
WELL TEST PROCEDURES MANUAL
DISTRIBUTION LIST
Eni - Agip Division Italian Districts
Eni - Agip Division Affiliated Companies
Eni - Agip Division Headquarter Drilling & Completion Units
STAP Archive
Eni - Agip Division Headquarter Subsurface Geology Units
Eni - Agip Division Headquarter Reservoir Units
Eni - Agip Division Headquarter Coordination Units for Italian Activities
Eni - Agip Division Headquarter Coordination Units for Foreign Activities
NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-
Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni -
Agip Division Headquarter)
Date of issue:
„
ƒ
‚
•
€ Issued by P. Magarini
E. Monaci
C. Lanzetta A. Galletta
28/06/99 28/06/99 28/06/99
REVISIONS PREP'D CHK'D APPR'D
28/06/99

ARPO
ENI S.p.A.
Agip Division
IDENTIFICATION CODE PAGE 2 OF 108
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INDEX
1. INTRODUCTION 7
1.1. Purpose of the manual 7
1.2. Objectives 7
1.3. Drilling Installations 8
1.4. UPDATING, AMENDMENT, CONTROL & DEROGATION 9
2. TYPES OF PRODUCTION TEST 10
2.1. Drawdown 10
2.2. Multi-Rate Drawdown 10
2.3. Build-up 10
2.4. Deliverability 10
2.5. Flow-on-Flow 11
2.6. Isochronal 11
2.7. Modified Isochronal 11
2.8. Reservoir Limit 11
2.9. Interference 12
2.10. Injectivity 12
3. GENERAL ROLES AND RESPONSIBILITIES 13
3.1. Responsibilities and Duties 13
3.1.1. Company Drilling and Completion Supervisor 14
3.1.2. Company Junior Drilling and Completion Supervisor 14
3.1.3. Company Drilling Engineer 14
3.1.4. Company Production Test Supervisor 14
3.1.5. Company Well Site Geologist 15
3.1.6. Contractor Toolpusher 15
3.1.7. Contract Production Test Chief Operator 15
3.1.8. Contractor Downhole Tool Operator 15
3.1.9. Wireline Supervisor 15
3.1.10. Company Stimulation Engineer 15
3.1.11. Company Reservoir Engineer 15
3.2. Responsibilities And Duties On Short Duration Tests 16
3.2.1. Company Drilling and Completion Supervisor 16
3.2.2. Company Junior Drilling and Completion Supervisor 16
3.2.3. Company Well Site Geologist 16
3.2.4. Contractor Personnel 16
4. WELL TESTING PROGRAMME 17
4.1. Contents 17

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5. SAFETY BARRIERS 18
5.1. Well Test Fluid 18
5.2. Mechanical Barriers - Annulus Side 19
5.2.1. SSTT Arrangement 19
5.2.2. Safety Valve Arrangement 21
5.3. Mechanical Barriers - Production Side 22
5.3.1. Tester Valve 22
5.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV) 23
5.4. Casing Overpressure Valve 23
6. TEST STRING EQUIPMENT 24
6.1. General 24
6.2. Common Test Tools Description 29
6.2.1. Bevelled Mule Shoe 29
6.2.2. Perforated Joint/Ported Sub 29
6.2.3. Gauge Case (Bundle Carrier) 29
6.2.4. Pipe Tester Valve 29
6.2.5. Retrievable Test Packer 29
6.2.6. Circulating Valve (Bypass Valve) 29
6.2.7. Pipe Tester Valve 30
6.2.8. Safety Joint 30
6.2.9. Hydraulic Jar 30
6.2.10. Downhole Tester Valve 30
6.2.11. Single Operation Reversing Sub 30
6.2.12. Multiple Operation Circulating Valve 30
6.2.13. Drill Collar 31
6.2.14. Slip Joint 31
6.2.15. Crossovers 31
6.3. High Pressure Wells 31
6.4. Sub-Sea Test Tools Used On Semi-Submersibles 31
6.4.1. Fluted Hanger 31
6.4.2. Slick Joint (Polished Joint) 31
6.4.3. Sub-Sea Test Tree 31
6.4.4. Lubricator Valve 32
6.5. Deep Sea Tools 32
6.5.1. Retainer Valve 32
6.5.2. Deep Water SSTT 32
7. SURFACE EQUIPMENT 33
7.1. Test Package 33
7.1.1. Flowhead Or Surface Test Tree 33
7.1.2. Coflexip Hoses And Pipework 33
7.1.3. Data/Injection Header 34
7.1.4. Choke Manifold 34
7.1.5. Steam Heater And Generator 35
7.1.6. Separator 35
7.1.7. Data Acquisition System 36
7.1.8. Gauge/Surge Tanks And Transfer Pumps 36
7.1.9. Diverter Manifolds, Burners and Booms 37

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7.2. Emergency Shut Down System 38
7.3. Accessory Equipment 39
7.3.1. Chemical Injection Pump 39
7.3.2. Sand Detectors 39
7.3.3. Crossovers 40
7.4. Rig Equipment 40
7.5. Data Gathering Instrumentation 40
7.5.1. Offshore Laboratory and Instrument Manifold Equipment 40
7.5.2. Separator 41
7.5.3. Surge Or Metering Tank 41
7.5.4. Steam Heater 41
8. BHP DATA ACQUISITION 42
8.1.1. Quartz Crystal Gauge 42
8.1.2. Capacitance Gauge 42
8.1.3. Strain Gauge 42
8.1.4. Bourdon Tube Gauge 43
8.2. Gauge Installation 43
8.2.1. Tubing Conveyed Gauges 43
8.2.2. Gauge Carriers 43
8.2.3. SRO Combination Gauges 44
8.2.4. Wireline Conveyed Gauges 44
8.2.5. Memory Gauges Run on Slickline 44
8.2.6. Electronic Gauges Run on Electric Line 45
9. PERFORATING SYSTEMS 46
9.1. Tubing Conveyed Perforating 46
9.2. Wireline Conveyed Perforating 46
9.3. Procedures For Perforating 46
10. PREPARING THE WELL FOR TESTING 48
10.1. Preparatory Operations For Testing 48
10.1.1. Guidelines For Testing 7ins Liner Lap 48
10.1.2. Guidelines For Testing 95
/8ins Liner Lap 48
10.1.3. General Technical Preparations 48
10.2. Brine Preparation 49
10.2.1. Onshore Preparation of Brine 49
10.2.2. Transportation and Transfer of Fluids 49
10.2.3. Recommendations 49
10.2.4. Rig Site Preparations 50
10.2.5. Well And Surface System Displacement To Brine 52
10.2.6. Displacement Procedure 52
10.2.7. On-Location Filtration And Maintenance Of Brine 52
10.3. Downhole Equipment Preparation 53
10.3.1. Test tools 53
10.4. TUBING PREPARATION 54
10.4.1. Tubing Connections 54
10.4.2. Tubing Grade 55

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10.4.3. Material 55
10.4.4. Weight per Foot 55
10.4.5. Drift 55
10.4.6. Capacity 55
10.4.7. Displacement 55
10.4.8. Torque 56
10.4.9. AGIP (UK) Test String Specification 56
10.4.10. Inspection 57
10.4.11. After Testing/Prior To Re-Use 58
10.4.12. Tubing Movement 58
10.5. Landing String Space-Out 58
10.5.1. Landing String space-Out Procedure 60
10.6. GENERAL WELL TEST PREPARATION 61
10.6.1. Crew Arrival on Location 61
10.6.2. Inventory of Equipment Onsite 62
10.6.3. Preliminary Inspections 62
10.7. Pre Test Equipment Checks 63
10.8. Pressure Testing Equipment 65
10.8.1. Surface Test Tree 66
11. TEST STRING INSTALLATION 68
11.1. General 68
11.2. TUBING HANDLING 69
11.3. RUNNING AND PULLING 70
11.4. Packer And Test String Running Procedure 71
11.5. Running the Test String with a Retrievable Packer 71
11.6. Running a Test String with a Permanent Packer 72
12. WELL TEST PROCEDURES 74
12.1. Annulus Control And Pressure Monitoring 74
12.2. Test Execution 74
13. WELL TEST DATA REQUIREMENTS 76
13.1. General 76
13.2. Metering Requirements 77
13.3. Data Reporting 78
13.4. Pre-Test Preparation 78
13.5. Data Reporting During the Test 78
13.6. Communications 79
14. SAMPLING 80
14.1. Conditioning The Well 80
14.2. Downhole Sampling 80

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14.3. Surface Sampling 81
14.3.1. General 81
14.3.2. Sample Quantities 82
14.3.3. Sampling Points 82
14.3.4. Surface Gas Sampling 83
14.4. Surface Oil Sampling 85
14.5. Sample Transfer And Handling 86
14.6. Safety 87
14.6.1. Bottom-hole Sampling Preparations 87
14.6.2. Rigging Up Samplers to Wireline 87
14.6.3. Rigging Down Samplers from Wireline 87
14.6.4. Bottomhole Sample Transfer And Validations 88
14.6.5. Separator/Wellhead Sampling 88
14.6.6. Sample Storage 88
15. WIRELINE OPERATIONS 89
16. HYDRATE PREVENTION 90
17. NITROGEN OPERATIONS 91
18. OFFSHORE COILED TUBING OPERATIONS 92
19. WELL KILLING ABANDONMENT 93
19.1. Routine Circulation Well Kill 93
19.1.1. Circulation Well Kill Procedure 93
19.2. Bullhead Well Kill 95
19.2.1. Bullhead Kill procedure 95
19.3. Temporary Well Kill For Disconnection On Semi Submersibles 96
19.4. Plug And Abandonment/Suspension Procedures 97
19.5. Plug and Abandonment General Procedures 97
20. HANDLING OF HEAVYWATER BRINE 98

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Agip Division
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1. INTRODUCTION
The main objective when drilling a well is to test and evaluate the target formation. The normal
method of investigating the reservoir is to conduct a well test. There are two types of well test
methods available:
• Drill Stem Test (DST). The scope is to define the quality of the formation fluid.
Where drillpipe/tubing in combination with downhole tools is used as a short term
test to evaluate the reservoir. The formation fluid may not reach or only just reach
the surface during the flowing time.
• Production Test. The scope is to define the quality and quantity of the formation
fluid. Many options of string design are available depending on the requirements of
the test and the nature of the well.
Many designs of well testing strings are possible depending on the requirements of the test
and the nature of the well and the type of flow test to be conducted but basically it consists of
installing a packer tailpipe, packer, safety system and downhole test tools and a tubing or drill
pipe string then introducing a low density fluid into the string in order to enable the well to flow
through surface testing equipment which controls the flow rate, separates the fluids and
measures the flow rates and pressures.
A short description of the types of tests which can be conducted and generic test string
configurations for the various drilling installations, as well as the various downhole tools
available, surface equipment, pre-test procedures and test procedures are included in this
section.
Well test specific wireline and coiled tubing operations are also included.
1.1. PURPOSE OF THE MANUAL
The purpose of the manual is to guide technicians and engineers, involved in Eni-Agip’s
Drilling & Completion worldwide activities, through the Procedures and the Technical
Specifications which are part of the Corporate Standards.
Such Corporate Standards define the requirements, methodologies and rules that enable to
operate uniformly and in compliance with the Corporate Company Principles. This, however,
still enables each individual Affiliated Company the capability to operate according to local
laws or particular environmental situations.
The final aim is to improve performance and efficiency in terms of safety, quality and costs,
while providing all personnel involved in Drilling & Completion activities with common
guidelines in all areas worldwide where Eni-Agip operates.
1.2. OBJECTIVES
The test objectives must be agreed by those who will use the results and those who will
conduct the test before the test programme is prepared. The Petroleum Engineer should
discuss with the geologists and reservoir engineers about the information required and make
them aware of the costs and risks involved with each method. They should select the easiest
means of obtaining data, such as coring, if possible. Such inter-disciplinary discussions
should be formalised by holding a meeting (or meetings) at which these objectives are
agreed and fixed.

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Agip Division
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The objectives of an exploration well test are to:
• Conduct the testing in a safe and efficient manner.
• Determine the nature of the formation fluids.
• Measure reservoir pressure and temperature.
• Interpret reservoir permeability-height product (kh) and skin value.
• Obtain representative formation fluid samples for laboratory analysis.
• Define well productivity and/or injectivity.
• investigate formation characteristics.
• Evaluate boundary effects.
1.3. DRILLING INSTALLATIONS
Well tests are conducted both onshore and offshore in either deep or shallow waters. The
drilling units from which testing can be carried out include:
Land Rigs,
Swamp Barges
Jack-Up Rigs
The preferred method for testing on a land rig installation
necessitates the use of a permanent/retrievable type production
packer, seal assembly and a conventional flowhead or test tree with
the test string hung of in the slips. In wells where the surface
pressure will be more than 10,000psi the BOPs will be removed
and testing carried out with a tubing hanger/tubing spool and a
Xmas tree arrangement. This requires all the necessary
precautions of isolation to be taken prior to nippling down the BOPs
Semi-Submersible The preferred method for testing from a Semi-submersible is by
using a drill stem test retrievable packer. However where
development wells are being tested, the test will be conducted
utilising a production packer and sealbore assembly so that the well
may be temporarily suspended at the end of the test. When testing
from a Semi-submersible the use of a Sub-Sea Test Tree
assembly is mandatory.
It consists of hanger and slick joint which positions the valve/latch
section at the correct height in the BOP stack and around which the
pipe rams can close to seal of the annulus. The valve section
contains two fail-safe valves, usually a ball and flapper valve types.
At the top of the SSTT is the hydraulic latch section which contains
the operating mandrels to open the valves and the latching
mechanism to release this part of the tree from the valve section in
the event that disconnection is necessary.
Drill Ship Same as Semi-Submersible above.

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Agip Division
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1.4. UPDATING, AMENDMENT, CONTROL & DEROGATION
This is a ‘live’ controlled document and, as such, it will only be amended and improved by the
Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates
operational experience. Accordingly, it will be the responsibility of everyone concerned in the
use and application of this manual to review the policies and related procedures on an
ongoing basis.
Locally dictated derogations from the manual shall be approved solely in writing by the
Manager of the local Drilling and Completion Department (D&C Dept.) after the
District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in
Eni-Agip Division Head Office have been advised in writing.
The Corporate Drilling & Completion Standards Department will consider such approved
derogations for future amendments and improvements of the manual, when the updating of
the document will be advisable.

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Agip Division
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2. TYPES OF PRODUCTION TEST
2.1. DRAWDOWN
A drawdown test entails flowing the well and analysing the pressure response as the reservoir
pressure is reduced below its original pressure. This is termed drawdown. It is not usual to
conduct solely a drawdown test on an exploration well as it is impossible to maintain a
constant production rate throughout the test period as the well must first clean-up. During a
test where reservoir fluids do not flow to surface, analysis is still possible. This was the
original definition of a drill stem test or DST. However, it is not normal nowadays to plan a test
on this basis.
2.2. MULTI-RATE DRAWDOWN
A multi-rate drawdown test may be run when flowrates are unstable or there are mechanical
difficulties with the surface equipment. This is usually more applicable to gas wells but can be
analysed using the Odeh-Jones plot for liquids or the Thomas-Essi plot for gas.
It is normal to conduct a build-up test after a drawdown test.
The drawdown data should also be analysed using type curves, in conjunction with the build
up test.
2.3. BUILD-UP
A build-up test requires the reservoir to be flowed to cause a drawdown then the well is
closed in to allow the pressure to increase back to, or near to, the original pressure which is
termed the pressure build-up or PBU. This is the normal type of test conducted on an oil well
and can be analysed using the classic Horner Plot or superposition.
From these the permeability-height product, kh, and the near wellbore skin can be analysed.
On low production rate gas wells, where there is a flow rate dependant skin, a simple form of
test to evaluate the rate dependant skin coefficient, D, is to conduct a second flow and PBU at
a different rate to the first flow and PBU. This is the simplest form of deliverability test
described below.
2.4. DELIVERABILITY
A deliverability test is conducted to determine the well’s Inflow Performance Relation, IPR,
and in the case of gas wells the Absolute Open Flow Potential, AOFP, and the rate dependant
skin coefficient, D.
The AOFP is the theoretical fluid rate at which the well would produce if the reservoir sand
face was reduced to atmospheric pressure.
This calculated rate is only of importance in certain countries where government bodies set
the maximum rate at which the well may be produced as a proportion of this flow rate.

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There are three types of deliverability test:
• Flow on Flow Test.
• Isochronal Test.
• The Modified Isochronal Test.
2.5. FLOW-ON-FLOW
Conducting a flow-on-flow test entails flowing the well until the flowing pressure stabilises and
then repeating this at several different rates. Usually the rate is increased at each step
ensuring that stabilised flow is achievable. The durations of each flow period are equal. This
type of test is applicable to high rate gas well testing and is followed by a single pressure build
up period.
2.6. ISOCHRONAL
An Isochronal test consist of a similar series of flow rates as the flow-on-flow test, each rate
of equal duration and separated by a pressure build-up long enough to reach the stabilised
reservoir pressure. The final flow period is extended to achieve a stabilised flowing pressure
for defining the IPR.
2.7. MODIFIED ISOCHRONAL
The modified isochronal test is used on tight reservoirs where it takes a long time for the shut-
in pressure to stabilise. The flow and shut-in periods are of the same length, except the final
flow period which is extended similar to the isochronal test. The flow rate again is increased
at each step.
2.8. RESERVOIR LIMIT
A reservoir limit test is an extended drawdown test which is conducted on closed reservoir
systems to determine their volume. It is only applicable where there is no regional aquifer
support. The well is produced at a constant rate until an observed pressure drop, linear with
time, is achieved. Surface readout pressure gauges should be used in this test.
It is common practice to follow the extended drawdown with a pressure build-up. The
difference between the initial reservoir pressure, and the pressure to which it returns, is the
depletion. The reservoir volume may be estimated directly from the depletion, also the volume
of produced fluid and the effective isothermal compressibility of the system. The volume
produced must be sufficient, based on the maximum reservoir size, to provide a measurable
pressure difference on the pressure gauges, these must therefore be of the high accuracy
electronic type gauges with negligible drift.

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Agip Division
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2.9. INTERFERENCE
An interference test is conducted to investigate the average reservoir properties and
connectivity between two or more wells. It may also be conducted on a single well to
determine the vertical permeability between separate reservoir zones.
A well-to-well interference test is not carried out offshore at the exploration or appraisal stage
as it is more applicable to developed fields. Pulse testing, where the flowrate at one of the
wells is varied in a series of steps, is sometimes used to overcome the background reservoir
pressure behaviour when it is a problem.
2.10. INJECTIVITY
In these tests a fluid, usually seawater offshore is injected to establish the formation’s
injection potential and also its fracture pressure, which can be determined by conducting a
step rate test. Very high surface injection pressures may be required in order to fracture the
formation.
The water can be filtered and treated with scale inhibitor, biocide and oxygen scavenger, if
required. Once a well is fractured, which may also be caused by the thermal shock of the
cold injection water reaching the sandface, a short term injection test will generally not provide
a good measure of the long term injectivity performance.
After the injectivity test, the pressure fall off is measured. The analysis of this test is similar to
a pressure build-up, but is complicated by the cold water bank.

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3. GENERAL ROLES AND RESPONSIBILITIES
Well testing is potentially hazardous and requires good planning and co-operation/co-
ordination between all the parties involved.
The most important aspect when planning a well test, is the safety risk assessment process.
To this end, strict areas of responsibilities and duties shall be defined and enforced, detailed
below.
3.1. RESPONSIBILITIES AND DUTIES
The following Company’s/Contractor’s personnel shall be present on the rig:
• Company Drilling and Completion Supervisor.
• Company Junior Drilling and Completion Supervisor.
• Company Drilling Engineer.
• Company Production Test Supervisor.
• Company Well Site Geologist.
• Contractor Toolpusher.
• Contract Production Test Chief Operator.
• Contractor Downhole Tool Operator.
• Wireline Supervisor (slickline & electric line ).
• Tubing Power Tong Operator.
• Torque Monitoring System Engineer.
Depending on the type of test, the following personnel may also be required on the rig during
the Well test:
• Company Stimulation Engineer.
• Company Reservoir Engineer.

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Agip Division
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3.1.1. Company Drilling and Completion Supervisor
The Company Drilling and Completion Supervisor retains overall responsibility on the rig
during testing operations. He is assisted by the Company Production Test Supervisor, Drilling
Engineer, Well Site Geologist and Company Junior Drilling and Completion supervisor. When
one of the above listed technicians is not present, the Company Drilling and Completion
Supervisor, in agreement with Drilling and Completion Manager and Drilling Superintendent,
can perform the test, after re-allocation of the duties and responsibilities according to the Well
Test specifications. If deemed necessary he shall request that the rig be inspected by a
Company safety expert prior to starting the well test.
3.1.2. Company Junior Drilling and Completion Supervisor
The Company Junior Drilling and Completion Supervisor will assist the Company Drilling and
Completion Supervisor in well preparation and in the test string tripping operation. He will co-
operate with the Company Production Test Supervisor to verify the availability of downhole
drilling equipment, to carry out equipment inspections and tests and to supervise the
Downhole Tool Operator and the Contractor Production Chief Operator. In co-operation with
the Drilling Engineer, he will prepare daily reports on equipment used. In the absence of the
Company Junior Drilling and Completion Supervisor, his function will be performed by the
Company Drilling and Completion Supervisor.
3.1.3. Company Drilling Engineer
The Drilling Engineer will assist the Company Drilling and Completion Supervisor in the well
preparation and in the test string tripping operation. He will co-operate with the Company
Production Test supervisor to supervise the downhole tool Operator and the Contractor
Production Chief Operator. He shall be responsible for supplying equipment he is concerned
with (downhole tools) and for preliminary inspections. He shall provide Contractor personnel
with the necessary data, and prepare accurate daily reports on equipment used in co-
operation with the Company Junior Drilling and Completion Supervisor.
3.1.4. Company Production Test Supervisor
The Company Production Test Supervisor is responsible for the co-ordination and conducting
of the test. This includes well opening, flow or injection testing, separation and measuring,
flaring, wireline, well shut in operations and all preliminary test operations required on specific
production equipment. In conjunction with the Reservoir Engineer, he shall make
recommendations on test programme alterations whenever test behaviour is not as expected.
The final decision to make any programme alterations will be taken by head office.
The Company Production Test Supervisor will discuss and agree the execution of each
phase of the test with the Company Drilling and Completion Supervisor. He will then inform rig
floor and test personnel of the actions to be performed during the forthcoming phase of the
test. He will be responsible for co-ordination the preparation of all reports and telexes,
including the final well test report.
He is responsible for arranging the supply of all equipment necessary for the test i.e. surface
and down hole testing tools, supervising preliminary inspections as per procedures. He will
supervise contract wireline and production test equipment operator’s, as well as the downhole
tool operator and surface equipment operators. He will be responsible in conjunction with the
Company Well site Geologist for the supervision of perforating and cased hole logging
operations, as per the test programme.
The Company Production Test Supervisor is responsible for the preparation of all reports,

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including the final field report previously mentioned.
3.1.5. Company Well Site Geologist
The Well Site Geologist is responsible for the supervision of perforating operations (for well
testing) cased hole logging when the Company Production Test Supervisor is not present on
the rig. If required he will co-operate with the Company Production Test Supervisor for the test
interpretation and preparation of field reports.
3.1.6. Contractor Toolpusher
The Toolpusher is responsible for the safety of the rig and all personnel. He shall ensure that
safety regulations and procedures in place are followed rigorously. The Toolpusher shall
consistently report to the Company Drilling and Completion supervisor on the status of drilling
contractors material and equipment.
3.1.7. Contract Production Test Chief Operator
The Production Test Chief Operator shall always be present to co-ordinate and assist the well
testing operator and crew. He will be responsible for the test crew to the Company Production
Test Supervisor and will draw up a chronological report of the test.
3.1.8. Contractor Downhole Tool Operator
The downhole tool operator will remain on duty, or be available, on the rig floor from the time
the assembling of the BHA is started until it is retrieved. He is solely responsible for downhole
tool manipulation and annulus pressure control during tests.
On Semi-Submersibles the SSTT operator will be available near the control panel on the rig
floor from the time when the SSTT is picked up until it is laid down again at the end of the test.
During preliminary inspections of equipment, simulated test (dummy tests), tools tripping in
and out of the hole and during the operations relating to the well flowing (from opening to
closure of tester ), he will report to the Company Production Test Supervisor.
3.1.9. Wireline Supervisor
The Wireline Supervisor will ensure all equipment is present and in good working order. He
will report directly with the Company Production Test Supervisor.
3.1.10. Company Stimulation Engineer
If present on the rig, the Stimulation Engineer will assist the Company Production Test
Supervisor during any stimulation operations. He will provide the Company Production Test
Supervisor with a detailed programme for conducting stimulation operations, including the
deck layout for equipment positioning, chemical formulations, pumping rates and data
collection. He will monitor the contractors during the stimulation to ensure the operation is
performed safely and satisfactorily.
The Stimulation Engineer will also provide the Company Production Test Supervisor with a
report at the end of the stimulation operation.
3.1.11. Company Reservoir Engineer
If present on the rig, the Reservoir Engineer shall assist the Company Production Test

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Supervisor during the formation testing operation. His main responsibility is to ensure that the
required well test data is collected in accordance to the programme and for the quality of the
data for analysis. He will provide a quick look field analysis of each test period and on this
basis he will advise on any necessary modifications to the testing programme.
3.2. RESPONSIBILITIES AND DUTIES ON SHORT DURATION TESTS
As a general rule the only company personnel present on the rig shall be the Company Drilling
and Completion Supervisor, the Company Junior Drilling and Completion Supervisor and the
well site Geologist, the Company Drilling Manager/Superintendent shall evaluate, in each
individual case, the opportunity of providing a company Drilling Engineer. The responsibilities
and duties of the Company Drilling and Completion Supervisor and Well Site Geologist will be
as follows:
3.2.1. Company Drilling and Completion Supervisor
The Company Drilling and Completion Supervisor retains overall responsibility on the rig
during testing operations assisted by the Company Junior Drilling and Completion Supervisor
and the well site Geologist. He is responsible for the co-ordination of testing operations, well
preparation for tests, shut-in of the well, formation clean out, measuring, flaring and wireline
operations. The Company Drilling and Completion Supervisor is responsible for the availability
and inspection of the testing equipment. He shall supervise the contractor Production Chief
Operator, Wireline Operator and Production Test Crew, as well as the Downhole Tool
Operator and Surface Tool Operator.
3.2.2. Company Junior Drilling and Completion Supervisor
The Company Junior Drilling and Completion Supervisor shall assist the Company Drilling
and Completion Supervisor to accomplish his duties. He shall also prepare accurate daily
reports on equipment used.
3.2.3. Company Well Site Geologist
The Well Site Geologist is responsible for the supervision of perforating operations and for
cased hole logging operations. He is responsible for the final decision making to modify the
testing programme, whenever test behaviour would be different than expected. He shall draw
up daily and final reports on the tests and is responsible for the first interpretation of the test.
3.2.4. Contractor Personnel
For the allocation of responsibilities and duties of contractor’s Personnel (Toolpusher,
Production Chief Operator, Downhole Tool Operator), refer to long test responsibilities.

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4. WELL TESTING PROGRAMME
When the rig reaches Total Depth (TD) and all the available data is analysed, the company
Reservoir/Exploration Departments shall provide the Company Drilling/Production and
Engineering departments with the information required for planning the well test (type,
pressure, temperature of formation fluids, intervals to be tested, flowing or sampling test,
duration of test, type of completion fluid, type and density of fluid against which the well will be
opened, type of perforating gun and number of shots per foot, use of coiled tubing stimulation,
etc.).
The Drilling, Production and Engineering departments shall then prepare a detailed testing
programme verifying that the testing equipment conforms to these procedures. The duty of
the Engineering Department is also to make sure that the testing equipment is available at the
rig in due time.
Company and contractor personnel on the rig shall confirm equipment availability and
programme feasibility, verifying that the test programme is compatible with general and
specific rules related to the drilling unit.
Governmental bodies of several countries lay down rules and regulations covering the entire
drilling activity. In such cases , prior to the start of testing operations a summary programme
shall be submitted for approval to national agencies, indicating well number, location,
objectives, duration of test and test procedures.
Since it is not practical to include all issued laws within the company general statement the
company (Drilling, Production, Engineering departments and rig personnel) shall verify the
consistency of the present procedures to suit local laws, making any modifications that would
be required. However, at all times, the most restrictive interpretation shall apply.
4.1. CONTENTS
The programme shall be drawn up in order to acquire all necessary information taking into
account two essential factors:
• The risk to which the rig and personnel are exposed during testing.
• The cost of the operation.
A detailed testing programme shall include the following points:
• A general statement indicating the well status, targets to be reached, testing
procedures as well as detailed safety rules that shall be applied, should they differ
from those detailed in the current procedures.
• Detailed and specific instructions covering well preparation, completion and
casing perforating system, detailed testing programme field analysis on test data
and samples, mud programme and closure of the tested interval.

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5. SAFETY BARRIERS
Barriers are the safety system incorporated into the structure of the well and the test string
design to prevent uncontrolled flow of formation fluids and keep well pressures off the casing.
It is common oilfield practice to ensure there are at least two tested barriers in place or
available to be closed at all times. A failure in any barrier system which means the well
situation does meet with this criteria, then the test will be terminated and the barrier replaced,
even if it entails killing of the well to pull the test string.
To ensure overall well safety, there must be sufficient barriers on both the annulus side and
the production or tubing side. Some barriers may actually contain more than one closure
mechanism but are still classified as a single barrier such as the two closure mechanism in a
SSTT, etc.
Barriers are often classified as primary, secondary and tertiary.
This section describes the barrier systems which must be provided on well testing
operations.
5.1. WELL TEST FLUID
The fluid which is circulated into the wellbore after drilling operations is termed the well test
fluid and conducts the same function as a completion fluid and may be one and the same if
the well is to be completed after well testing. It provides one of the functions of a drilling fluid,
with regards to well control, in that it density is designed to provide a hydrostatic overbalance
on the formation which prevents the formation fluids entering the wellbore during the times it
is exposed to the test fluid during operations. The times that the formation may be exposed to
the test fluid hydrostatic pressure are when:
• A casing leak develops.
• The well is perforated before running the test string.
• There is a test string leak during testing.
• A circulating device accidentally opens during testing.
• Well kill operations are conducted after the test.
During the testing operation when the packer is set and the well is flowing, the test fluid is only
one of the barriers on the annulus side.
The test fluid density will be determined form log information and calculated to provide a
hydrostatic pressure, generally between 100-200psi, greater than the formation pressure.
completion. As the test fluid is usually a clear brine for damage prevention reasons, high
overbalance pressures may cause severe losses and alternatively, if the overbalance
pressure is too low, any fluid loss out of the wellbore may quickly eliminated the margin of
overbalance. When using low overbalance clear fluids, it is important to calculate the
temperature increase in the well during flow periods as this decreases the density.
An overbalance fluid is often described as the primary barrier during well operations.

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A modern test method used on wells which have high pressures demanding high density test
fluids which are unstable an extremely costly, is to design the well test with an underbalanced
fluid which is much more stable and cheaper. In this case there will be one barrier less than
overbalance testing. This is not a problem providing the casing is designed for the static
surface pressures of the formation fluids and that all other mechanical barriers are available
and have been tested.
5.2. MECHANICAL BARRIERS - ANNULUS SIDE
On the annulus side, the mechanical barriers are:
• Packer/tubing envelope.
• Casing/BOP pipe ram/side outlet valves envelope.
Therefore, under normal circumstances there are three barriers on the annulus side with the
overbalance test fluid. If one of these barriers (or element of the barrier) failed then there
would still be two barriers remaining.
An alternate is when the BOPs are removed and a tubing hanger spool is used with a Xmas
tree. In this instance the barrier envelope on the casing side would be casing/hanger
spool/side outlet valves.
The arrangement of the BOP pipe ram closure varies with whether there is a surface or
subsea BOP stack. When testing from a floater, a SSTT is utilised to allow the rig to suspend
operations and leave the well location for any reason. On a jack-up, a safety valve is installed
below the mud line as additional safety in the event there is any damage caused to the
installation (usually approx. 100m below the rig floor). Both systems use a slick joint spaced
across the lower pipe rams to allow the rams to be closed on a smooth OD.
5.2.1. SSTT Arrangement
A typical SSTT arrangement is shown in figure 5.a. The positioning of the SSTT in the stack is
important to allow the blind rams to be closed above the top of the SSTT valve section
providing additional safety and keeping the latch free from any accumulation of debris which
can effect re-latching.
Note: The shear rams are not capable of cutting the SSTT assembly unless a
safety shear joint is installed in the SSTT across the shear ram position.

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Figure 5.A- SSTT Arrangement

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5.2.2. Safety Valve Arrangement
On jack-ups where smaller production casing is installed, the safety valve may be too large in
OD (7-8ins) to fit inside the casing. In this instance a spacer spool may be added between the
stack and the wellhead to accommodate the safety valve. This is less safe than having the
valve positioned at the mud line as desired (Refer to figure 5.b )
Figure 5.B - Safety Valve Arrangement
PIPE RAMS
SHEAR RAMS
5” PIPE RAMS
5” SLICK JOINT
8 ” O . D .
S A F E T Y V A L V E
9 5/8” CASING
TUBING
TUBING SPOOL
ALL WELLS
WITH 9 5/8”
PROD. CASING
TUBING
1 3 3 / 8 ” o r 1 1 ” 5 0 0 0 - 1 0 0 0 0 - 1 5 0 0 0 p s i W . P . B O P S T A C K S
TUBING SPOOL
TUBING SPOOL TUBING SPOOL
TUBING SPOOL
5.25” O.D.
SAFETY VALVE
8” O.D.
SAFETY VALVE
8” O.D.
SAFETY VALVE
8” O.D.
SAFETY VALVE
7” CASING 7” CASING 7” CASING
7” CASING
5” SLICK JOINT
5” SLICK JOINT
5” SLICK JOINT 5” SLICK JOINT
JACK UP, FIXED PLATFORMS and ON-SHORE RIGS WITH 7” PRODUCTION CASING
ALL WELLS
WITH 7”
PROD. CASING
PIPE RAMS
SPACER SPOOL
0.6 to 1.0 metre long
SPACER SPOOL
0.6 to 1.0 metre long
SPACER SPOOL
minimum 1 metre long
for fixed platforms

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5.3. MECHANICAL BARRIERS - PRODUCTION SIDE
On the production side there are a number of barriers or valves which may be closed to shut-
off well flow. However some are solely operational devices. The barriers used in well control
are:
Semi-submersible string - Latched
• Tester valve
• SSTT
• Surface test tree.
Semi-submersible string - Unlatched
• Tester valve
• SSTT.
Jack-Up
• Tester valve
• Safety valve
Land well
• Tester valve
• Safety valve
5.3.1. Tester Valve
The tester valve is an annulus pressure operated fail safe safety valve. It remains open by
maintaining a minimum pressure on the annulus with the cement pump. Bleeding off the
pressure or a leak on the annulus side closes the valve.
The tester may have an alternate lock open cycle device and it is extremely important that this
type of valve is set in the position where the loss of pressure closes the valve. It is unsafe to
leave the tester valve in the open cycle position as in an emergency situation there may not
be sufficient time to cycle the valve closed.
The tester valve may be considered as the primary barrier during the production phase.

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5.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV)
This is a valve normally installed about 100m below the wellhead or below the mud line in
permanent on-shore and off-shore completions respectively.
This type of valve can also be installed inside the BOP for well testing as an additional
downhole barrier on land wells or on jack-up rigs, see figure 5.b for the various configurations
of BOP stacks combinations relating to the production casing size.
Due to the valve OD (7-8ins) available today in the market, its use with 7” production casing is
only possible by installing a spacer spool between the tubing spool and the pipe rams closed
on a slick joint directly connected to the upper side of the valve itself. A space of at least two
metres between pipe rams and top of tubing spool is required.
The valve OD must be larger than the slick joint to provide a shoulder to prevent upward string
movement.
A small size test string with a 5.25ins OD safety valve can be used with 7ins casing, as
indicated.
In all cases the valve is operated by hydraulic pressure through a control line and is fail safe
when this pressure is bled off. The slick joint body has an internal hydraulic passage for the
control line.
The safety valve can be considered the secondary barrier during production.
5.4. CASING OVERPRESSURE VALVE
A test string design which includes an overpressure rupture disk, or any other system
sensible to casing overpressure, should have an additional single shot downhole safety valve
to shut off flow when annulus pressure increases in an uncontrolled manner.
This additional safety feature is recommended only in particular situations where there are
very high pressures and/or production casing is not suitable for sudden high overpressures
due to the test string leaking.
This valve is usually used with the single shot circulating valve which is casing pressure
operated and positioned above the safety valve, hence will open at the same time the safety
valve closes. This allows the flow line to bleed off the overpressure.

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6. TEST STRING EQUIPMENT
6.1. GENERAL
The well testing objectives, test location and relevant planning will dictate which is the most
suitable test string configuration to be used. Some generic test strings used for testing from
various installations are shown over leaf:
In general, well tests are performed inside a 7ins production liner, using full opening test tools
with a 2.25ins ID. In larger production casing sizes the same tools will be used with a larger
packer. In 5-51
/2ins some problems can be envisaged: availability, reliability and reduced ID
limitations to run W/L. tools, etc. smaller test tools will be required, but similarly, the tools
should be full opening to allow production logging across perforated intervals. For a barefoot
test, conventional test tools will usually be used with a packer set inside the 95
/8ins casing.
If conditions allow, the bottom of the test string should be 100ft above the top perforation to
allow production logging, reperforating and/or acid treatment of the interval.
In the following description, tools which are required both in production tests and conventional
tests are included. The list of tools is not exhaustive, and other tools may be included.
However, the test string should be kept as simple as possible to reduce the risk of
mechanical failure. The tools should be dressed with elastomers suitable for the operating
environment, considering packer fluids, prognosed production fluids, temperature and the
stimulation programme, if applicable.
The tools must be rated for the requested working pressure (in order to withstand the
maximum forecast bottom-hole/well head pressure with a suitable safety factor).

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Figure 6.A- Typical Jack Up/Land Test String - Packer With TCP Guns On Packer

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Figure 6.B - Typical Test String - Production Packer With TCP Guns Stabbed Through

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Figure 6.C - Typical Jack Up/Land Test String - Retrievable Packer

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Figure 6.D - Typical Semi-Submersible Test String - Retrievable Packer

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6.2. COMMON TEST TOOLS DESCRIPTION
6.2.1. Bevelled Mule Shoe
If the test is being conducted in a liner the mule shoe makes it easier to enter the liner top.
The bevelled mule shoe also facilities pulling wireline tools back into the test string.
If testing with a permanent packer, the mule shoe allows entry into the packer bore.
6.2.2. Perforated Joint/Ported Sub
The perforated joint or ported sub allows wellbore fluids to enter the test string if the tubing
conveyed perforating system is used. This item may also be used if wireline retrievable
gauges are run below the packer.
6.2.3. Gauge Case (Bundle Carrier)
The carrier allows pressure and temperature recorders to be run below or above the packer
and sense either annulus or tubing pressures and temperatures.
6.2.4. Pipe Tester Valve
A pipe tester valve is used in conjunction with a tester valve which can be run in the open
position in order to allow the string to self fill as it is installed. The valve usually has a flapper
type closure mechanism which opens to allow fluid bypass but closes when applying tubing
pressure for testing purposes. The valve is locked open on the first application of annulus
pressure which is during the first cycling of the tester valve.
6.2.5. Retrievable Test Packer
The packer isolates the interval to be tested from the fluid in the annulus. It should be set by
turning to the right and includes a hydraulic hold-down mechanism to prevent the tool from
being pumped up the hole under the influence of differential pressure from below the packer.
6.2.6. Circulating Valve (Bypass Valve)
This tool is run in conjunction with retrievable packers to allow fluid bypass while running in
and pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. It
can also be used to equalise differential pressures across packers at the end of the test. It is
automatically closed when sufficient weight is set down on the packer.
This valve should ideally contain a time delay on closing, to prevent pressuring up of the
closed sump below the packer during packer setting. This feature is important when running
tubing conveyed perforating guns which are actuated by pressure. If the valve does not have a
delay on closing, a large incremental pressure, rather than the static bottomhole pressure,
should be chosen for firing the guns

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6.2.7. Pipe Tester Valve
A pipe tester valve is used in conjunction with a tester valve which can be run in the open
position in order to allow the string to self fill as it is installed. The valve usually has a flapper
type closure mechanism which opens to allow fluid bypass but closes when applying tubing
pressure for testing purposes.
The valve is locked open on the first application of annulus pressure which is during the first
cycling of the tester valve.
6.2.8. Safety Joint
Installed above a retrievable packer, it allows the test string above this tool to be recovered in
the event the packer becomes stuck in the hole. It operates by manipulating the string (usually
a combination of reciprocation and rotation) to unscrew and the upper part of the string
retrieved. The DST tools can then be laid out and the upper part of the safety joint run back in
the hole with fishing jar to allow more powerful jarring action.
6.2.9. Hydraulic Jar
The jar is run to aid in freeing the packer if it becomes stuck. The jar allows an overpull to be
taken on the string which is then suddenly released, delivering an impact to the stuck tools.
6.2.10. Downhole Tester Valve
The downhole tester valve provides a seal from pressure from above and below. The valve is
operated by pressuring up on the annulus. The downhole test valve allows downhole shut in
of the well so that after-flow effects are minimised, providing better pressure data. It also has
a secondary function as a safety valve.
6.2.11. Single Operation Reversing Sub
Produced fluids may be reversed out of the test string and the well killed using this tool. It is
actuated by applying a pre-set annulus pressure which shears a disc or pins allowing a
mandrel to move and expose the circulating ports. Once the tool has been operated it cannot
be reset, and therefore must only be used at the end of the test.
This reversing sub can also be used in combination with a test valve module if a further safety
valve is required. One example of this is a system where the reversing sub is combined with
two ball valves to make a single shot sampler/safety valve.
6.2.12. Multiple Operation Circulating Valve
This tool enables the circulation of fluids closer to the tester valve whenever necessary as it
can be opened or closed on demand and is generally used to install an underbalance fluid for
brining in the well.
This tool is available in either annulus or tubing pressure operated versions. The tubing
operated versions require several pressure cycles before the valve is shifted into the
circulating position. This enables the tubing to be pressure tested several times while running
in hole. Eni-Agip’s preference is the annulus operated version.

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6.2.13. Drill Collar
Drill collars are required to provide a weight to set the packer. Normally two stands of 43
/4ins
drill collars (46.8lbs/ft) should be sufficient weight on the packer, but should be regarded as
the minimum.
6.2.14. Slip Joint
These allow the tubing string to expand and contract in the longitudinal axis due to changes in
temperature and pressure. They are non-rotating to allow torque for setting packers or
operating the safety joint.
6.2.15. Crossovers
Crossovers warrant special attention They are of the utmost importance as they connect
every piece of equipment in the test string which have differing threads. If crossovers have to
be manufactured, they need to be tested and fully certified. In addition, they must be checked
with each mating item of equipment before use.
6.3. HIGH PRESSURE WELLS
If the SBHP >10,000psi a completion type test string and production Xmas tree is
recommended to test the well.
6.4. SUB-SEA TEST TOOLS USED ON SEMI-SUBMERSIBLES
The sub-sea test tree (SSTT) assembly includes a fluted hanger, slick joint, and sub-sea test
tree.
6.4.1. Fluted Hanger
The fluted hanger lands off and sits in the wear bushing of the wellhead and is adjustable to
allow the SSTT assembly to be correctly positioned in the BOP stack so that when the SSTT
is disconnected the shear rams can close above the disconnect point.
6.4.2. Slick Joint (Polished Joint)
The slick joint (usually 5ins OD) is installed above the fluted hanger and has a smooth (slick)
outside diameter around which the BOP pipe rams can close and sustain annulus pressure
for DST tool operation or, if in an emergency disconnection, contain annulus pressure. The
slick joint should be positioned to allow the two bottom sets of pipe rams to be closed on it
and also allow the blind rams to close above the disconnect point of the SSTT.
6.4.3. Sub-Sea Test Tree
The SSTT is a fail-safe sea floor master valve which provides two functions; the shut off of
pressure in the test string and; disconnection of the landing string from the test string due to
an emergency situation or for bad weather. The SSTT is constructed in two parts; the valve
assembly consisting of two fail safe closed valves and; a latch assembly. The latch contains
the control ports for the hydraulic actuation of the valves and the latch head.

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The control umbilical is connected to the top of the latch which can, under most
circumstances be reconnected, regaining control without killing the well. The valves hold
pressure from below, but open when a differential pressure is applied from above, allowing
safe killing of the well without hydraulic control if unlatched.
6.4.4. Lubricator Valve
The lubricator valve is run one stand of tubing below the surface test tree. This valve
eliminates the need to have a long lubricator to accommodate wireline tools above the
surface test tree swab valve. It also acts as a safety device when, in the event of a gas
escape at surface, it can prevent the full unloading of the contents in the landing string after
closing of the SSTT. The lubricator valve is hydraulic operated through a second umbilical line
and should be either a fail closed or; fail-in-position valve. When closed it will contain pressure
from both above and below
6.5. DEEP SEA TOOLS
6.5.1. Retainer Valve
The retainer valve is installed immediately above the SSTT on tests in extremely deep waters
to prevent large volumes of well fluids leaking into the sea in the event of a disconnect. It is
hydraulic operated and must be a fail-open or fail-in-position valve. When closed it will contain
pressure from both above and below. It is usually run in conjunction with a deep water SSTT
described below.
6.5.2. Deep Water SSTT
As exploration moves into deeper and remote Subsea locations, the use of dynamic
positioning vessels require much faster SSTT unlatching than that available with the normal
hydraulic system on an SSTT. The slow actuation is due to hydraulic lag time when bleeding
off the control line against friction and the hydrostatic head of the control fluid. This is
overcome by use of the deepwater SSTT which has an Electro-Hydraulic control system.
The Hydraulic deep water actuator is a fast response controller for the deepwater SSTT
and retainer valve. This system uses hydraulic power from accumulators on the tree
controlled electrically from surface (MUX). The fluid is vented into the annulus or an
atmospheric tank to reduce the lag time and reducing closure time to seconds.
If a programme required deepwater test tools, the tool operating procedures would be
included in the test programme.

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7. SURFACE EQUIPMENT
This sub-section contains the list of surface equipment and the criteria for use.
7.1. TEST PACKAGE
7.1.1. Flowhead Or Surface Test Tree
Modern flowheads are of solid block construction, i.e. as a single steel block, as opposed to
the earlier modular unit which was assembled from various separate components.
Irrespective of the type, both should contain:
• Upper Master Valve for emergency use only.
• Lower Master Valve situated below the swivel for emergency use only.
• Kill Wing Valve on the kill wing outlet connected to the cement pump or the rig
manifold.
• Flow Wing Valve on the flow wing outlet, connected to the choke manifold, which
is the ESD actuated valve.
• Swab Valve for isolation of the vertical wireline or coil tubing access.
• Handling Sub which is the lubricator connection for wireline or coiled tubing and is
also for lifting the tree.
• Pressure Swivel which allows string rotation with the flow and kill lines connected.
With the rig at its operating draft, the flowhead should be positioned so that it is at a distance
above the drill floor which is greater than the maximum amount of heave anticipated, plus an
allowance for tidal movement, i.e. 5ft and a further 5ft safety margin.
Coflexip hoses are used to connect from the flowhead kill wing and flow wing to the rig
manifold and the test choke manifold. A permanently installed test line is sometimes available
which leads from the drill floor to the choke manifold location.
7.1.2. Coflexip Hoses And Pipework
Coflexip hoses must be installed on the flowhead correctly so as to avoid damage. They must
be connected so that they hang vertically from the flowhead wings. The hoses should never
be hung across a windwall or from a horizontal connection unless there is a pre-formed
support to ensure they are not bent any tighter than their minimum radius of 5ft.
Hoses are preferred to chiksan connections because of their flexibility, ease of hook up and
time saving. They are also less likely to leak due to having fewer connections. On floaters,
they connect the stationary flowhead to the moving rig and its permanent pipework.
Permanently installed surface lines should be used with the minimum of temporary
connections supplied from the surface testing contractor. Ideally these temporary
connections should be made-to-measure pipe sections with welded connections, however
chiksans can be used but must be tied down to the deck.

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Additional protection can be given by installing relief valves in the lines. Is now common
practice to have a relief valve on the line between the heater and the separator to cater for any
blockage downstream which may cause over-pressure in the line. If there is further risk from
plugging of the burner nozzles by sand carry-over, then consideration should be given to
installing further relief valves downstream of the separator to protect this lower pressure rated
pipework.
Note: Ensure that the Coflexip hoses are suitable for use with corrosive brines.
7.1.3. Data/Injection Header
This item is usually situated immediately upstream of the choke. The data/injection header is
merely a section of pipe with several ports or pockets to mount the following items:
• Chemical injection
• Wellhead pressure recording
• Temperature recording
• Wellhead pressure recording with a dead weight tester
• Wellhead sampling
• Sand erosion monitoring
• Bubble hose.
Most of the pressure and temperatures take off points will be duplicated for the Data
Acquisition System sensors.
7.1.4. Choke Manifold
The choke manifold is a system of valves and chokes for controlling well flow and usually has
one adjustable and one fixed choke. Some choke manifolds may also incorporate a bypass
line. The valves are used to direct the flow through either of the chokes or the bypass. They
also provide isolation from pressure so that the choke changes can be made.
A well shall be brought in using the adjustable or variable choke. This choke should never be
fully closed against well flow. The flow should then be redirected to the appropriately sized
fixed choke for stable flow conditions. The testing contractor should ensure that a full range of
fixed chokes are available in good condition.
Due to the torturous path of the fluids through the choke, flow targets are positioned where the
flow velocities are high and impinge on the bends. Ensure these have been checked during
the previous refurbishment to confirm they were still within specification.

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7.1.5. Steam Heater And Generator
Heat is required from the steam heater, or heat exchanger, to:
• Prevent hydrate formation on gas wells
• Prevent wax deposition when testing high waxy, paraffin type crudes
• Break foams or emulsions
• Reduce viscosity of heavy oils.
For use on high flow rate wells, a 4ins bore steam heater should be used to reduce high back
pressures.
The heat required to raise a gas by 1o
F can be estimated from the formula:
2,550 x Gas Flow (mmscf/day) x Gas Specific Gravity (air = 1.000), BTU/hr/o
F
The heat needed to raise an oil by 1o
F can be estimated from:
8.7 x Oil Flow (bbls/day) x Oil Density (gms/cm3), BTU/hr/o
F
Always use the largest steam heater and associated generator that space or deck loading will
allow as the extra output is contingency for any serious problem which may arise. The rig
steam generator will not usually have the required output and therefore diesel-fired steam
generator in conjunction with the steam heat exchanger should be supplied by the surface
test contractor.
7.1.6. Separator
The test separator is required to:
• Separate the well flow into three phases; oil, gas and water
• Meter the flow rate of each phase, at known conditions
• Measure the shrinkage factor to correct to standard conditions
• Sample each phase at known temperature and pressure.
The standard offshore separator is a horizontal three phase, 1,440psi working pressure unit.
This can handle up to 60mmscf/day of dry gas or up to 10,000bopd and associated gas at its
working pressure Other types of separator, such as the vertical or spherical models and two-
phase units may be used.
Gas is metered using a Daniel’s or similar type orifice plate gas meter. The static pressure,
pressure drop across the orifice plate and the temperature are all recorded. From this data
the flow rate is calculated.
The liquid flowrates are measured by positive displacement or vortex meters.
The oil shrinkage factor is physically measured by allowing a known volume of oil, under
controlled conditions, to de-pressurise and cool to ambient conditions. The shrinkage factor is
the ambient volume, divided by the original volume. The small volume, however, of the
shrinkage meter means that this is not an accurate measurement.

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The oil flow rate is corrected for any volume taken up by gas, water, sand or sediment. This
volume is calculated by multiplying the combined volume by the BS&W measurement and the
tank/meter factor. Oil meters are calibrated onshore but it is also necessary to divert the oil
flow to a gauge tank for a short period to obtain a combined shrinkage/meter factor as the
meter calibration is subject to discrepancy with varying oil gravity and viscosity.
The separator relief system is calibrated onshore and should never be function tested
offshore, hence the separator should only be tested to 90% of the relief valve setting.
It is important that the separator bypass valves, diverter valves for the vent lines leading from
the separator relief valve, rupture disc or back-up relief valve, are checked for ease of
operation.
7.1.7. Data Acquisition System
It is now common custom to use computerised Data Acquisition Systems (DAS) on offshore
well tests. However, it is essential that manual readings are still separately recorded for
correlation of results and contingency in the event of problems occurring to the system.
These systems can collect, store and provide plots of:
• Surface data
• Downhole data from gauges
• Memory gauge data.
The main advantage of DAS is that real time plots can be displayed at the well site for
troubleshooting. Another advantage is that all of the surface (and possibly downhole) data is
collected into one system and can be supplied on a floppy disk for the operator to analyse and
subsequently prepare well reports.
7.1.8. Gauge/Surge Tanks And Transfer Pumps
A gauge tank is an atmospheric vessel whereas a surge tank is usually rated to 50psi WP
and is vented to the flare. A surge tank is essential for safe working if H2S production is
anticipated. Therefore, surge tanks should always be used on wildcat wells and gauge tanks
used only in low risk situations.
Tanks are used for checking the oil meter/shrinkage factors and for measuring volumes at
rates which are too low for accurate flow meter measurement. They usually have a capacity
of one hundred barrels and some with twin compartments so that one compartment can be
filled while the other is pumped to the burner via the transfer pump.
Tanks can also be used for collecting large atmospheric samples of crude for analysis or
used as a secondary separator for crudes which require longer separation times. Some tanks
can have special features such as steam heating elements for heavy/viscous oil production
tests etc.

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7.1.9. Diverter Manifolds, Burners and Booms
Burner heads are mounted on the end of the booms which are usually installed on opposing
sides of the rig to take maximum advantage of wind direction changes, i.e. to keep at least
one burner heading downwind. The oil and gas flowlines, including the tank and relief vent
lines, from the test area to the booms, must have diverter manifolds for directing flow to the
leeward boom.
Most recent designs of burners are promoted as ‘green’ or ‘clean’ type burners. This is
indicative of them being less polluting to the environment by having superior burning
technology. Although still not ‘ideal’ their ability is much improved over previous models.
The burner has a ring of atomisers or nozzles which break up the flow for complete
combustion. This is assisted by pumping air into the flow stream. Rig air must not be used for
this purpose as there is a risk of hydrocarbons leaking back into the rig air system. Two
portable air compressors, one as back-up, are required, suitably fitted with check valves. It is
recommended that the air compressors are manifolded together to provide a continuous
supply of air in the event of a compressor failure.
Green style burners are very heavy users of air and consideration must be given for deck
space for additional air compressors.
Water must be pumped to the burner head which forms a heat shield in the form of a spray
around the flare to protect the installation from excessive heat. It also aids combustion and
cools the burner head. Water must also be sprayed on the rig to keep it cool and special
attention must be given to the lifeboats. It is now normal for a rig to have a permanent spray
system installed and water may be provided by the rig pumps.
The burners have propane pilot lights which are ignited using a remote spark ignition system.
For heavy/viscous oil tests a large quantity of propane may be required. If this is the case,
mud burners should be requested, as they are specially designed to handle oil-based mud.
They can also better handle the clean-up flow. Alternatively, diesel can be spiked in at the oil
manifold using the cement pumps to assist combustion but, if there is only partial
combustion, carry over can cause pollution. Oil slicks can also be ignited and be a hazard to
the rig. If a heavy/viscous oil production test is planned, sufficient gauge tanks should be on
hand to conduct a test without flaring the oil.

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Figure 7.A- Surface Equipment Layout
7.2. EMERGENCY SHUT DOWN SYSTEM

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The Emergency Shut Down (ESD) system is the primary safety system in the event of an
uncontrolled escape of hydrocarbons at surface. The system consists of a hydraulically or
pneumatically operated flowhead flow wing valve, control panel and a number of remotely air
operated pilot valves. When a pilot or the main valve in the panel is actuated, it causes a loss
of air pressure in turn dropping out the main hydraulic valve which releases the pressure from
the flowhead ESD valve actuator.
The push button operated pilot valves are strategically placed at designated accessible areas
where the test crew and/or rig crew can actuate them by pushing the button when they
observe an emergency situation. Other pilots may be high or low pressure actuated pilots
installed at critical points in the system to protect equipment from over-pressure or under-
pressure which would indicate an upstream valve closure, blockage or leak etc. The system
is also actuated if a hose is cut or melted by heat from a fire, also releasing the air pressure.
7.3. ACCESSORY EQUIPMENT
7.3.1. Chemical Injection Pump
The main chemicals that are injected into the production flow are hydrate inhibitors, de-
foamers, de-emulsifiers and wax inhibitors. The chemicals are injected by an air driven
chemical injection pump at, either the data/injection header, flowhead or at the SSTT/sub-
surface safety valve. Chemicals must be supplied with toxicological and safety data sheets
as per regulations.
7.3.2. Sand Detectors
Sonic type sand detectors can be installed at the data/injection header upstream of the choke
if sand production is expected to cause erosion. These devices operate by detecting the
impingement of sand on a probe inserted into the flowstream. The accuracy is reasonable in
single phase gas flow but less consistent in multi-phase flow.
The simplest approach to sand detection is to take frequent BS&W samples at the
data/injection manifold to monitor for sand production. If the flow rates are low, samples taken
from the high side of flowline might incorrectly show little or no sand, therefore a suitable
sample point must also be available on the low side of the manifold. Samples should then be
collected from both points. The problem with this method is determining if the sand is causing
erosion or not. An erosion coupon or probe can also be installed on the manifold which will
indicate if erosion is occurring.
When sand production is anticipated on a test, sand traps should be employed. These large,
high pressure vessels would be situated upstream of the choke manifold and remove the
sand before it reaches the higher velocity flow rates at the choke. Control of the flowrate also
can prevent erosion by keeping it below the point where sand is lifted up the wellbore to
surface; however, this inflicts severe limitations on the test design.
Erosion can eventually cause:
• Reduced pipe wall thickness and cutting of holes in pipework, including valves
and chokes.
• Damaging (sandblasting) the separator and filling it with sand.
• Cutting out of burner nozzles.
• Sanding up the well and possibly plugging of downhole test tools.

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7.3.3. Crossovers
Crossovers warrant special attention They are of the utmost importance as they connect
every piece of equipment in the test string which have differing threads. If crossovers have to
be manufactured, they need to be tested and fully certified. In addition, they must be checked
with each mating item of equipment before use.
7.4. RIG EQUIPMENT
The main items of rig equipment used for testing, such as the permanent pipework and water
spray system have been addressed previously. However, it is essential that all the necessary
rig equipment which is to be used, has been checked. This includes the rig water pumps,
cement pumps, mud pumps and the BOPs. The BOP rams must be dressed in accordance
with the test programme.
Also there are some smaller items of equipment required which must be made available.
These include; long bails for rigging up equipment above the flowhead, rabbits for drifting the
tubulars, TIW type safety valves with crossovers, tongs and other pipe-handling equipment,
accurate instrumentation for monitoring annulus pressure, etc.
7.5. DATA GATHERING INSTRUMENTATION
This section describes the instrumentation required for measuring flow rates, pressures,
temperatures, gas and fluid properties which is listed below:
7.5.1. Offshore Laboratory and Instrument Manifold Equipment
• Hydrometer for measuring gravity of produced liquids.
• Manometer for calibrating DP meters.
• Shrinkage tester to allow the calculation of production in stock tank barrels.
• Dead-weight tester for pressure gauge checking and calibration.
• Gas gravitometer to measure gas gravity.
• Centrifuge for determining BS&W content.
• Selection of pressure gauges.
• Draeger tubes for measuring H2S and CO2 concentrations.
• Chemical injection pump.
• Surface pressure recorder.
• Water composition analysis test kit.
• Vacuum pump for evacuating sample containers.
• Downhole sampling kit.
Some instrumentation is mounted on the test equipment such as:

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7.5.2. Separator
• Oil flow meters on both separator oil lines.
• Gas flow meter.
• Thermometers.
• Pressure gauges.
7.5.3. Surge Or Metering Tank
• Sight glasses and graduated scales.
• Thermometer.
• Pressure Gauge.
7.5.4. Steam Heater
• Temperature controller.
Other special instrumentation must be listed in the specific test programme.

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8. BHP DATA ACQUISITION
The two of the most important parameters measured during well testing are downhole
pressures and temperatures. This data is obtained from BHP gauges installed as close to the
perforations as is practicable. BHP gauges are either mechanical or electronic type gauges.
The mechanical BHP gauge is rarely used today as it accuracy does not generally meet the
demands of engineers for modern analysis. It does still have uses on high temperature wells
where the temperature is above the limit of electronic gauges or when simple low cost
surveys are required; for instance, to obtain bottom hole pressure before a workover. They
are cheaper due to the lower gauge purchase cost and because it is not necessary to have a
gauge specialist to run them.
The electronic gauge is used in most circumstances and there are a number of different
models on the market with a wide range of accuracy and temperature specifications to meet
various test demands. It is critical to ensure that the gauge selected is fit for purpose as some
of the higher accuracy gauges are more susceptible to damage like the crystal gauge and
also more expensive. The criteria used should be to select the most robust and cost
competitive gauge which meets the test requirements. Currently there are three basic types
of pressure sensors used in electronic gauges available: Quartz Crystal, Capacitance, and
Strain.
The electronic gauge can operate through an electric cable for surface read out in real time
but more generally is run with an memory section which stores the data electronically on
chips. The early gauges had a very limited storage capacity of around 2.5K data points but
this has dramatically increased where gauges now have up to 500K. They can also be
programmed to change the sampling speed at various times and/or on pressure change
(∆p). This provides the reservoir engineer with accurate data at the desired and most critical
points in the test.
Both mechanical and electronic types of gauges are listed below in order of decreasing
accuracy.
8.1.1. Quartz Crystal Gauge
The principle of the gauge is the change in capacitance of the sensor crystal when pressure
is applied. The gauge has two quartz crystals, one sensor and one reference crystal. The
change in capacitance of the sensor crystal is measured by the change in frequency of an
oscillating circuit. The resultant frequency is converted to a pressure.
This type of gauge is the most accurate available. Poor temperature resolution used to be the
Achilles’ heel of the crystal gauge but modern gauges have overcome this problems by
having the temperature sensor built into the crystal assembly. The tool is comparatively
delicate because of the fragility of the crystals.
8.1.2. Capacitance Gauge
The principle of this gauge is similar to the quartz crystal gauge. The difference is that a
quartz substrate is used instead of a crystal. The gauge accuracy is between that of the
quartz and the strain gauge but is much more robust than the crystal gauge. It did not suffer
from poor temperature resolution like the earlier crystal gauges as the temperature sensor is
an integral part of the pressure diaphragm.
8.1.3. Strain Gauge
The strain gauge principle works on the deflection of a diaphragm. Pressure acting one side

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of the diaphragm causes the deflection which is measured and translated into pressure. The
accuracy of the gauge is lower than the quartz or the capacitance. This type of gauge is
extremely robust and is not affected by temperature changes.
8.1.4. Bourdon Tube Gauge
This is a mechanical gauge and was the first type of pressure gauge and is very robust. The
most common manufacturers were Amerada and Kuster. The well pressure elastically
deforms a Bourdon tube, the deflection of which is scribed directly on a time chart. After
recovery of the chart it is read and translated into pressure. Charts can be read with hand
operated chart reader or electronically by a computerised chart reader. The gauge accuracy
is much lower than any of the electronic gauges.
8.2. GAUGE INSTALLATION
As pointed out in the previous section, the gauges should be installed as deep as possible in
the well in order to obtain pressure and temperature data as near to formation conditions as
possible. On a well test this can be done by one of two methods: tubing conveyed or on
wireline.
8.2.1. Tubing Conveyed Gauges
The normal means of running gauges on the test string is in gauge carriers but other SRO
systems have been developed to obtain data from downhole gauges without having to pull the
string. This is an advancement in technology which means the data can be verified before
curtailing the test. This is extremely useful in very tight reservoirs where the end of the flow or
build up periods is difficult to predict and determine. In these tools the gauges are mounted in
a housing which is ported to below the tester valve.
8.2.2. Gauge Carriers
Gauges may be placed in gauge carriers, which are installed in the test string as it is being
run and are retrieved at the end of the test when the string is pulled. A minimum of two gauge
carriers with at least four gauges should be run.
Depending upon the test string design, they may be installed above the packer sensing tubing
pressure or possibly with one below the packer to sense pressure as close as possible to the
reservoir. Irrespective of the position relative to the packer, they must be run below the tester
valve to obtain build up data. Below packer gauges are of simpler design as they are not
pressure containing or require porting to the tubing.
Each carrier should contain at least two gauges, and at least two of the total should be of the
capacitance type of gauge. By running at least one carrier above a retrievable type packer,
some data can be retrieved if the packer becomes stuck by backing the string off at the safety
joint. Also, the packer absorbs some shock from tubing conveyed guns providing protection
for the upper gauges.

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8.2.3. SRO Combination Gauges
Systems which allow the databanks of the gauges run in the upper gauge case to be read
have been developed. The disadvantages of the SRO system are thus eliminated as the
gauges may be read continually or periodically. However is not good practice to run the
interrogating tool until the well has been cleaned up. In the early days, these systems proved
to be very unreliable but great advances have since been made.
The latest systems use tried and proven tester valves for the downhole closure which are
ported to above the valve to a bank of memory gauges or transducers. The tool gathers and
stores the data until the interrogation tool is run by electric line into the memory section
housing where it can communicate with the memory section to download the data. These
data are usually transmitted through an inductive coupling or similar type device.
Obviously the tool must be run during a shut-in period. It is advisable that the tool is not
stationed in the well, i.e. latched into the housing, during flow periods unless absolutely
necessary. This reduces the risk from becoming stuck due to sand production or the wire
getting cut through flow erosion.
8.2.4. Wireline Conveyed Gauges
There are two systems for running memory gauges using wireline techniques. The first is to
place a nipple below the perforated tailpipe and to run and set the gauges in this nipple prior to
performing the test.
The second method is to use an SRO electronic gauge run and positioned in the well on
electric line which gives a real time direct readout of parameters at surface. A version of this
method can provide build up data in conjunction with a downhole shut-in tool, similar to the
SRO systems described earlier, except they use wire tension to open and close a separate
shut-in mechanism, usually a sliding sleeve type device.
8.2.5. Memory Gauges Run on Slickline
A number of memory gauges, usually three but can be as many a physically possible, may be
run in on slickline and set in a nipple positioned below the perforated joint. The advantages of
this system are that the well may be shut-in downhole, eliminating after flow effects. Also the
gauges may be recovered, e.g. after the first build-up, and the data interpreted before
completing the test.
This system should be considered in wells producing fluids which are corrosive to the electric
line, and where long exposure is to be avoided. Gauges are generally run with a shock
absorber to avoid damage from shock during the trip or when setting the wireline BHP gauge
hanger.

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8.2.6. Electronic Gauges Run on Electric Line
Gauges may be run on electric line to give a ‘real-time’ readout of data at surface. This is
called surface readout (SRO). In some versions the well must be shut-in at surface confusing
the build-up data with after flow effects. However, there are now systems which allow the well
to be shut-in downhole and still have SRO. The disadvantages of this method are that the
electric line must remain in the hole during the test, unless using a SRO combination tool
described above.
Considerable difficulty may be encountered in landing this type of tool in its receptacle after
perforating the well. The tool is not robust enough to be landed before perforating and debris
may obstruct the nipple after the initial flow. It is highly desirable to clean up the well before
running this type of equipment.

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9. PERFORATING SYSTEMS
Two methods are currently used to perforate wells: wireline conveyed guns or tubing
conveyed guns. Tubing conveyed perforating is the Eni-Agip preferred method for well test
operations, as the zones to be tested can be perforated underbalanced in one run, with large
charges. However, under some circumstances wireline conveyed guns may still be preferred.
Both methods are described in the following sections.
The type of explosive to be used is dependant mainly on the bottomhole temperature and the
length of time the guns are likely to be on bottom before firing (Refer to the ‘Completion
Manual-Perforating Section’)
9.1. TUBING CONVEYED PERFORATING
With this method the guns are run in the hole on the bottom of well testing string. Therefore,
the guns and charge size can be maximised for optimum perforation efficiency and long
perforation intervals can be fired in a single run. If required, a bull nose can be installed on the
bottom of guns to allow the test string to enter liner tops. Various methods of detonation can
be utilised, depending on well conditions.
9.2. WIRELINE CONVEYED PERFORATING
There are two alternatives when perforating using wireline conveyed guns: casing guns or
through-tubing guns. In both cases depth control is provided by running a Casing Collar
Locator (CCL) above the guns and the guns are fired by electrical signal.
Casing guns are large diameter perforators which cannot be run through normal tubing size.
Therefore they must be used prior to run the test string and in overbalance conditions.
Through-tubing guns are small diameter guns run through the test string. They can be used to
perforate underbalance, reducing the risk of damaging the formation with brine or mud
invasion immediately after perforating. The largest gun which can be safety run through the
standard test tools (2.25ins ID) is a 111
/16”.
9.3. PROCEDURES FOR PERFORATING
Procedures to be observed when perforating a production casing/liner are the following:
a) Operations involving the use of explosives shall only be performed by Contractor's
specialised personnel in charge for casing perforation. The number of person
involved shall be as low as possible. Only the Contractor's operator is allowed to
control electric circuits, to load and unload guns.
b) Nobody else, except for Contractor's operators, is allowed to remain in the
hazardous area during gun loading and tripping in and out of the hole.
c) Explosives shall be kept on the rig for the shortest possible time and during such
time they shall be stored in a designated locked container, marked with
international recognised explosive signs.
d) Any remainder at the end of the test shall be returned to shore.

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e) Maximum care shall be taken during transportation, loading and back-loading of
explosive. Explosive and detonators shall always be transported and stored in
separate containers. This also applies to defective detonators which have been
removed from a misfired gun. Transportation of primed gun is not allowed;
explosive shall be transported unarmed.
f) Explosive should never be stored in the vicinity of other hazardous materials, e.g.
flammable or combustible liquids, compressed gases and welding equipment.
g) Precise record must be kept of all explosives received, stowed or off-loaded.
h) Warning signals shall surround the hazardous area where explosives are used.
i) As an electric potential could trigger the detonators, any source of such potential
shall be switched off to avoid premature detonation. Such sources include any
radio transmitter (including crane radios) and welding equipment.
The Company Drilling and Completion Supervisor shall collect all portable radios
inside company office in order to avoid any possibility of untimely use.
Radio silence shall be observed while guns are being primed and while primed
guns are above seabed.
j) The following shall be advised prior to radio silence being in force:
• Stand by vessel.
• Helicopter operations.
• Company Shore Base.
• Other nearby installations.
k) In the event of uncontrollable sources of potential such as thunderstorms,
operations involving the use of explosive shall be suspended. The only exception
to the precaution mentioned above is the SAFE (Slapper Activated Firing
Equipment) which can be operated, under any weather condition, during radio
transmissions and welding operations.
l) Inspections shall be done to make sure that no electric field is generated between
the well and the rig (max. allowable potential difference is 0.25 V). In the event this
voltage is exceeded, all sources of electrical energy must be switched off (this
may preclude perforating at night).
m) When the casing is perforated before running the DST string, mud level in the well
shall be visually monitored.
n) When the casing is perforated before running the DST string, the well must be
filled with a fluid whose density shall be equal to the mud weight used for drilling,
unless reliable information would indicate a formation pressure allowing for a
lower density.
o) The same principle applies for the weight of the fluid in the tubing/casing annulus
when perforating after the DST string has been run.
p) The first casing perforation shall be performed in daylight. Subsequent series of
shots can be carried out at any time.

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10. PREPARING THE WELL FOR TESTING
This section describes the operations necessary to prepare the well for well testing.
10.1. PREPARATORY OPERATIONS FOR TESTING
10.1.1. Guidelines For Testing 7ins Liner Lap
1) While waiting on cement, test the BOP stack according to the Eni-Agip Well Control
Policy Manual procedures. Pull out of the hole with the test tool.
2) Run a 6ins bit/mill and clean out the 7ins liner to the landing collar (PBTD). The drilling
programme must allow for sufficient rat hole to enable TCP guns to be dropped off, if
required.
3) Run a cement bond/correlation log from PBTD to top of 7ins liner.
4) Run in hole with 95
/8ins packer assembly and perform positive and negative tests on
liner lap as per the Company Drilling and Completion Supervisor’s instructions. As a
guideline, conduct a positive test of the liner lap by applying approximately 400psi
pressure. Ensure that the burst rating of the 95
/8ins casing is not exceeded. Displace
the required amount of fluid from the drillpipe with base oil to give an approximate
drawdown on the liner lap and liner of 500psig in excess of maximum drawdown
pressure planned for the individual wells. Set the packer and monitor the well head
pressure for influx for 1hr. If the liner lap or liner is found to be leaking then a remedial
cementing programme will be advised.
10.1.2. Guidelines For Testing 95
/8ins Liner Lap
1) While waiting on cement, test the BOP stack according to the Eni-Agip Well Control
Policy Manual procedures. Pull out of the hole with the test tool.
2) Run a 81
/2ins bit/mill and clean out the 95
/8ins casing to the landing collar (PBTD). The
drilling programme must allow for sufficient rat hole to enable TCP guns to be dropped
off, if required.
3) Run a cement bond/correlation log from PBTD to above the packer setting depth.
10.1.3. General Technical Preparations
1) Surface well testing equipment should be installed and pressure tested as per the
procedures in Section 7.
2) DST tools should be laid out and tested on the pipe desk (Refer to Section 10.8).
3) Ensure that all downhole components of the test string are the proper size, i.e. OD, ID,
thread type and that the items are clean and clear of any rust, debris, junk, etc. All
threads and collars are to be cleaned properly on the rack. Make sure all crossovers are
correctly bevelled inside and outside.
4) Make a visual inspection to verify the condition of packer rubbers and all DST
equipment.
5) Drift all DST equipment to ensure full ID for wireline, coiled tubing or Surface Read Out
(SRO) tools to be run in the hole.

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10.2. BRINE PREPARATION
In order to efficiently utilise the completion brine system and achieve optimum results, the
brine should be treated and handled according to the recommendations outlined in the
following sections.
10.2.1. Onshore Preparation of Brine
1. Filter and recondition any (suitable) brine which is in stock.
2. Following the final filtration/reconditioning cycle of this stored fluid, re-weigh and adjust
as necessary to suit the conditions of the well.
3. Prepare balance of fluid from sacked material or liquid, as appropriate. Filter and
condition as necessary.
10.2.2. Transportation and Transfer of Fluids
The primary objective is to transport and transfer the fluid without losing density due to
dilution, losing volume, or contaminating of the fluid.
10.2.3. Recommendations
An independent surveyor should be engaged to perform the following duties:
1) Onshore Brine Tanks
• Dip storage tanks before transferring fluids.
• Take samples of brine at beginning, middle and end of pumping. If required,
submit to the district office.
• Check samples for SG at 60o
F; centrifuge for solids content, check clarity.
• Dip storage tanks after brine is loaded onto transport vessel.
• Record and submit report the volume and density of brine provided by brine
supplier.
2) Pumping into Vessel
• The independent surveyor should ensure that all transport tanks were/are
chemically cleaned.
• Visually inspect tanks for cleanliness, residue, any fluids not completely drained
from tanks, inspect pumps/manifolds if applicable.
• Dip vessel tanks and check volume as per vessel calibration charts versus
suppliers brine tank volumes.
• Close and seal all hatches on transport tanks.

ARPO
ENI S.p.A.
Agip Division
REVISION
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1) Off-loading Brine at Rig-Site
• Inspect pontoons/tanks/pits for cleanliness, report any residual solids or fluids and
ensure their removal prior to off-loading. Obtain calibration charts in order to
measure volume of fluid received.
• Sample brine received into pontoons/pits and check density and solids to verify
that fluid has not been diluted or contaminated during transport. Report any
variation from original quality.
• Ensure that required volumes are removed from transport tanks on vessel.
Report any residual fluid not transferred to the rig.
• Report and record final volume and density received on the rig.
10.2.4. Rig Site Preparations
The importance of initial cleanliness of mud/brine tanks, pumps, lines, etc. can not be over-
emphasised. The following procedures are recommended:
1) Brine Tanks and Lines
• All mud/brine tanks, sand traps, ditches, pumps, etc. that will be used for the brine
should be previously cleaned of solids and/or residual contaminants. All lines
should be pre-flushed with water and, if necessary, a chemical wash.
• If feasible, mixing lines and valves should be pressure tested against the mixing
pumps. Leaking valves should be replaced.
• The mud/brine tanks, ditches, lines and pumps can be given a final cleaning with
appropriate chemical cleaner and flushed with water. This final cleaning should
include all equipment surfaces which will come in contact with the brine.
• Finally ensure that all tanks, lines, pumps etc., are dry to avoid dilution of the
brine.
The mud pits should be cleaned as follows using seawater, prior to transferring
completion brine from storage tanks to the pits.
• When all the mud has been emptied from the pit tanks to be used, clean the mud
tanks as thoroughly as possible to avoid any brine contamination. Clean initially
using buckets and shovels.
• Wash the first mud pit with 50bbls seawater pill containing descaler and oil mud
removers.
• Pump pill into second pit and make up second 50bbls pill containing lower
concentration descaler/oil mud remover.
• Pump second pill into first pit and first pill into third pit. Continue the system until
all pits are clean, including slug and premix pits, and all the surface lines.
• Prepare a third 50bbls pill and pump again through all pits if required.
2) Dump Valves
Prior to receiving the brine, ensure all ‘O’ rings and seats are functioning correctly.
Leaking valves can cause significant brine losses.

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
3) Ditch Gates - Slide Type
All gates should be sealed prior to receiving brine. Two layers of ‘Densotape’ applied
across edge of slide should insure a good seal. Additional sealing can be obtained with
a fillet of ‘Slick grease’ on the upstream side.
Barites, bentonites and polymers should not be used in an attempt to seal possible
leaking areas. They do not provide adequate sealing, and also contaminate the brine.
4) Water Lines
All water lines should be taped or chained off.
5) Pump Packing
Replace all work mixing pump packing.
6) Tripping
Significant losses of brine can be avoided during tripping by:
• Using wiper plugs
• Using collection box and drip pan
• Slugging of pipe with heavier weight brine.
7) Rig Shakers
Should it be necessary to pass brine over rig shakers when circulating, ensure
equipment is operating properly. Avoid diluting brine by washing down or cleaning
screens with water.
8) Settling Pit
Tank or tanks should be dedicated to be used as settling/separation tanks for brine that
became abnormally contaminated during the course of the testing operation. Brines
contaminated with solids, oil, cement, or other should be placed in tanks and chemically
treated as required. For oil and solids and/or polymer-contamination, pilot testing should
be performed to determine treatments of flocculants and/or oil separation chemicals,
viscosity breakers, etc. Following chemical treatment, the brine should be filtered and
returned to the active system, and re-weighted if necessary.
9) Sand Traps
If used to contain brine during the operation, these traps should be thoroughly cleaned
prior to the introduction of the brine system. It should also be pre-determined that fluid
can be completely removed when required.

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
10.2.5. Well And Surface System Displacement To Brine
Most oil and water based drilling fluids, are incompatible with solids-free brines; therefore an
effective displacement/chemical wash should be planned to:
• Remove mud solids and contaminants from the well bore.
• Maintain the integrity of the mud and brine.
• Separate the mud and brine during displacement.
• Reduce filtration time and cost.
10.2.6. Displacement Procedure
Extensive displacement procedures will be issued by the Brine Contractor. The procedures
will be contained as part of the detailed well specific test programme.
The technique utilised may be one of two types:
• Indirect Displacement (of which a key ingredient is flushing the wellbore with large
volumes of water).
• Direct Displacement (where minimal seawater flushing is utilised).
Reference must be made to individual fluid companies procedures.
The completion brine can be prepared at base or at the well site according to circumstances.
Use a filtering system as required during the testing operations to keep brine in required
condition. Required completion fluid weight should be confirmed based on RFT and offset
well data. Once the hole has been displaced to completion brine, continue circulating if
necessary until completion brine returns are within specification as regards weight and
filtration quality.
10.2.7. On-Location Filtration And Maintenance Of Brine
Considering rig surface equipment and availability of space, every effort should be made to
follow procedures:
1) Install filtration equipment in order to operate at its maximum efficiency.
2) Filtration service company should advise proper DE filter aids and cartridge size to
ensure maximum filtration efficiency and economics based on type of fluid to be filtered,
anticipated contaminants such as barite solids, mud solids, oil, etc.
3) Brine in suction tank should be maintained at proper density and filtered prior to being
pumped into hole.
4) Returns of brine should be placed in adequate settling/separation tank to allow proper
chemical treatments and filtration before being placed into the active brine system.
5) If considered more economical and feasible, severely contaminated brine should be
returned to the brine supplier for reclamation and reconditioning. Whenever possible, a
sample of the contaminated brine should be sent to the brine supplier for evaluation to
determine if the fluid should be treated offshore or onshore.
6) Avoid dilution of brines caused by water hoses, water lines, washing down or rig and/or
filtration equipment, etc.

ARPO
ENI S.p.A.
Agip Division
REVISION
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7) Pick up bit for casing and drill out cement to the top of the liner. If it is planned to
perform a pressure or inflow test on the liner lap, a casing scraper should be run with
the bit unless excessive drilling is expected.
8) Run in the hole with bit for liner and drill out the liner to landing collar which is then the
PBTD (Refer to section 10.1).
9) Run and record CBL/VDL or CET from the landing collar to the top of the liner.
10) If there are reasons to believe that the integrity of the seal on the liner lap is not effective,
a pressure and/or inflow test should be performed (Refer to section 10.1).
11) If the liner lap is found to be leaking then a remedial cementing job is advised.
10.3. DOWNHOLE EQUIPMENT PREPARATION
10.3.1. Test tools
Downhole test equipment must be included in the preparation of the test string as they
become an integral part of the string. On both the primary and back-up sets, the following
tests and checks must be completed by the relevant service company crew:
1) Layout all of the tools on the pipe deck for inspection.
2) Measure the tools and provide a dimensional sketch for each, giving:
• Identification number
• Length
• Maximum outside diameter
• Minimum inside diameter
• Thread connection up
• Thread connection down
• Fishing neck dimensions.
3) Conduct a body pressure test to a minimum of 1,000psi above the maximum expected
differential pressure, or 1,000psi above the maximum wellhead pressure, whichever is
the greatest.
4) Pressure test, from direction of flow, all test string valves to a minimum of 1,000psi
above either the maximum expected differential pressure, or wellhead pressure,
whichever is the greatest.
5) Pressure test, from above, all test string valves, if appropriate, to a minimum of
1,000psi above either the maximum differential pressure, or wellhead pressure,
whichever is the greatest.
6) Where appropriate, the downhole test equipment should be function tested.
7) The test string components must be drifted to the 2.25ins maximum drift size to cater
for all contingencies.
8) These tests should be carried out on the pipedeck and the tools dressed with the
correct value shear pins or rupture discs, as per programme.
9) Check that the appropriate crossovers are available and make up to the downhole test
equipment.

ARPO
ENI S.p.A.
Agip Division
REVISION
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This equipment includes, but is not limited to:
• Lubricator Valve
• Retainer Valve
• Sub-sea Test Tree
• Circulating Valve(s)
• Tester Valve (with Hydraulic Reference Section, if appropriate)
• Gauge Carriers
• Permanent Packer Seal Assembly or Retrievable Packer and associated
Jars, Safety Joint and Slip Joints.
10.4. TUBING PREPARATION
Careful consideration of the tubing to be selected and how it is handled, checked and tallied is
essential in well testing operations. The following sub-sections provide a short description of
the important tubing aspects which need to be considered for a well test.
10.4.1. Tubing Connections
One of the important aspects to be considered in a well test is the type of thread connection
to be used for the tubing string.
Premium connections generally have better sealing properties compared with API
connections and can also have other special features such as:
• Higher strength
• Higher torque (good for use in horizontal wells)
• Faster make-up speeds
• Internally streamlined and recess free to prevent erosion
• Multi-reusable (less galling)
• Reduced connection stresses to reduce Hydrogen Sulphide attack.
The primary seal is metal-to-metal but some connections also have a secondary metal-to-
metal seals or a Teflon packing ring.
Some premium connections are superior to others regarding being gas tight or good for high
pressure and temperatures etc., therefore an operator must make a thorough investigation to
find the connection which is best fit for purpose. It is normally agreed that premium threads
with a torque shoulder such as Hydril is ideal for testing as it has low refurbishment costs and
is quick to make up and reasonably robust against handling damage, however it is limited to
the number of thread re-cuts that can be machined before requiring to be sent back to the mill
for upsetting again.
Typically, as an example of a good well test tubing, is Eni-Agip’s (UK) Affiliate who use a 41
/2”
15.5lbs/ft grade with the D95 SPJD-6 (Hydril compatible) thread connection for well testing.
The specification for this tubing is given in the following sub-sections.

ARPO
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Agip Division
REVISION
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10.4.2. Tubing Grade
Specifies the type and strength of the steel. Standard tubing is generally covered by the API
specifications, e.g. J 55, C 75, L 80, N 80, C 95. The letter signifies the properties of the steel
and the number signifies its minimum tensile strength in 1,000lbs per sq inch, i.e. N 80
signifies a normalised and tempered carbon steel with 80,000lbs/ins2
minimum yield. The
cross-sectional area of the tubing multiplied by the minimum yield stress provides the joint
yield strength, e.g. Agip (UK) tubing 41
/2ins 15.5lbs/ft C 95 body section is 4.407ins2
x
95,000lbs/ins2
- 419,000lbs. Tubing is manufactured in a variety of steel grades to cater for
the full range of well conditions and well effluents which may be encountered.
10.4.3. Material
The choice of tubing material should take into account the expected produced fluids. If sour
fluids are expected the material should be no harder than 22 HRC. This limits the choice to
C75 or N 80 as the toughest grades. However, special grades up to C 95 may be used if they
are specified for sour service and have passed the NACE sulphide stress cracking tests (API
SPEC 5AC).
Safety factors in axial tension should ideally not be less than 1.7, but a lower limit of 1.4 can
be accepted if a triaxial stress envelope is used. Agip (UK)’s test string is grade D 95 SG
(Dalmine designation, equivalent to C 95) and is suitable for tests where H2S is present.
10.4.4. Weight per Foot
Is a the term used in conjunction with the tubing OD in order to signify the thickness, e.g. 41
/2
ins 15.5lbs/ft has a wall thickness of 0.337ins hence an ID of 4.5 - (2 x 0.337) - 3.826ins.
10.4.5. Drift
Is slightly less than ID and represents maximum effective available bore diameter for the
passage of tools. API Spec 5A specifies the dimensions of mandrels to be used in drift
testing. All tubulars to be run in a well, i.e. casing, tubing, nipples, packers etc. must be drifted
prior to running.
10.4.6. Capacity
This is the amount of fluid required to fill a measured distance inside the tubing, e.g. the Agip
(UK) tubing has a capacity of 0.01422bbl/ft, sometimes expressed as 14.22 barrels per
thousand feet.
10.4.7. Displacement
This is the volume occupied by the tubing material, or the volume of fluid which the tubing will
displace.

ARPO
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Agip Division
REVISION
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10.4.8. Torque
Is the amount of rotational force applied to connect the pin and the box connections to
optimise the mechanical and sealing performance of the connections, e.g. the values for the
Agip (UK) string are as follows:
• Minimum - 6,800ft/lbs
• Optimum - 7,650ft/lbs
• Maximum - 8,500ft/lbs.
10.4.9. AGIP (UK) Test String Specification
Agip (UK) has its own full test string which is 41
/2ins OD with Dalmine SPJD 6 connections
(compatible with Hydril PH6 of the same size). The grade of this tubing is D 95-SG (equivalent
to C 95) which denotes Dalmine, 95,000psi minimum yield strength, Sour Gas service.
table 10.a provides dimensional strength and performance data for the Agip (UK) string.
TYPE: 41
/2OD - 15.5lbs/ft Grade D 95 Dalmine SPJ D - 6 (Hydril PH 6 Compatible)
Pipe Connection
ID 3.826ins 3.765ins
Drift 3.701ins
Torque Values
Min
Opt
Max
6,800ft/lbs
7,650ft/lbs
8,500ft/lbs
Capacity
0.01422bbls/ft
or
14.22bbls/1,000 ft
Displacement
0.00564bbls/ft
or
5.64bbls/1,000 ft
Burst 12,450psi
Collapse 12,760psi
Yield 419,000lbs
Table 10.A- AGIP (UK) Tubing Data

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
10.4.10. Inspection
Prior To Running (On Board Visual Inspection And Field Repair)
Ensure all connections are dried after cleaning and before inspection.
Check the starting threads to ensure they have no small slivers or edges of steel which could
indicate galling or over-torque.
Visual inspection should concentrate on the primary metal to metal seal surface of the pin and
box. These seals should be free from corrosion and defects.
The sealing mechanism is based on having sufficient pin-to-box metal-to-metal contact
stress around the full circumference of the connection. The pin and box seal surfaces should
be examined for any seal irregularity.
Check seal surface for:
• Longitudinal cuts and scratches
• Out-of-roundness
• Corrosion pits, rust and scale
• Galling.
Some type tubing connections have an external shoulder which is the primary shoulder on
these connections, controlling the position of the pin relative to the box. The proper location on
a fully made-up connection of all other seals and shoulders is determined by the position of
this shoulder.
The surface is also intended to be a secondary pressure seal. This requires that visual
inspection criteria similar to those used for the internal seal be used for the shoulder.
Check shoulder for:
• Radial cuts and scratches
• Out-of -roundness
• Corrosion pits, rust and scale
• Galling.
If the visual inspection detects some light corrosion/rust on the seal surface then this must be
removed before running. To alleviate this problem the rust or discoloration can be easily
removed by a light rubbing action using No 400 emery cloth or steel wool.
Minor thread damage (not seal) may be repaired with a fine needle file or No 400 emery cloth.
If any joints or connection show ovality then they should not be run.
If possible, note whether the pipe is straight, this may not be possible until the joint is being
run.
Drift pipe with correct size (OD and length) drift.

ARPO
ENI S.p.A.
Agip Division
REVISION
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10.4.11. After Testing/Prior To Re-Use
After a series of tests and before re-utilisation in another well, that part of the tubing used shall
be inspected onshore.
• Magnetic particle inspection, throughout the whole length
• Callipering
• Thread visual inspection
• Full length body log for cracking (e.g. Tuboscope)
• Hardness check.
10.4.12. Tubing Movement
As part of the design process for the testing string, calculations should be performed by the
DST contractor and confirmed by Agip to determine the likely maximum contraction and
expansion of the string during the various phases and operations of the test, i.e. circulation,
production, injection (acid or water injection test), killing, etc. This is to confirm the tubing
design is adequate for the test and to determine the optimum type and quantitative design of
any devices included in the string to accommodate tubing movement, e.g. slip joints or seal
assembly and sealbore packer.
10.5. LANDING STRING SPACE-OUT
This procedure is applicable to testing from Semi-submersibles.
The purpose of this procedure is to check the space-out of the fluted hanger, slick joint and
SSTT inside the Subsea BOPs and determine the length of landing string required to provide
the required height of the flowhead above the drill floor referred to a stick-up. It is vital that the
SSTT body does not lie across the shear/blind rams and that the surface tree is situated
sufficiently high enough above the drill floor so that on no account can the bottom of the tree
come into contact with the drill floor or the flow and kill lines become bound or trapped even at
the compound of the lowest tide with the greatest heave.
It is not necessary to run the actual SSTT and the backup hanger and slick joint may be used,
run on drillpipe. However, if space allows for the SSTT assembly, retainer valve and landing
string tubing to be set back in the derrick, it should be run and set back to save time later.
With some designs of trees the control hoses must be run to prevent accidental unlatching. A
joint of tubing, without a thread protector, should always be run beneath the SSTT.

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 10.A- SSTT Arrangement

ARPO
ENI S.p.A.
Agip Division
REVISION
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Figure 10.B - Typical Safety Valve Arrangement for a Jack-up
10.5.1. Landing String space-Out Procedure

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
The procedure is:
1) Check that the rig is at operating draft.
2) Make up the fluted hanger to the slick joint, with the appropriate adjustment, to give the
correct length according to the stack drawing dimensions.
3) Pick up the fluted hanger and slick joint assembly and paint the slick joint with white
paint.
4) Run in to immediately above the BOPs and engage the compensator.
5) Land the hanger in the wellhead. Pick up slightly and turn to the right to ensure the
hanger has fully landed out.
6) Carefully close the rams on the slick joint, checking the volume of fluid taken to confirm
that they are fully closed.
7) Mark the string at the drill floor at mid-heave.
8) Record the tide level.
9) Open the rams and strap out to the first connection to obtain the depth to the hang-off
point at this tide level.
10) Pull the pipe and lay out the hanger and slick joint being careful not to smudge the paint
marks.
11) Check where the ram marks are positioned on the slick joint. If the measure from the
centre of the rams to the wellhead housing does not correlate, then re-check the stack
dimensions.
12) Adjust the primary assembly for the dimensions obtained.
Note: Ensure that either choke or kill line is connected below pipe ram that is to
be used on slick joint. This is necessary for annulus control and
monitoring during DST operations.
10.6. GENERAL WELL TEST PREPARATION
10.6.1. Crew Arrival on Location
Contractor Service Specialist is to meet with the Company Representative and discuss the
test programme and any updates to the original programme. At this point potential problem
areas should be identified with the goal of preventing such problems or at least eliminating the
element of surprise. This policy should continue throughout the test as new information
becomes available or as conditions change.

ARPO
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Agip Division
REVISION
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10.6.2. Inventory of Equipment Onsite
The contractor shall:
1) Obtain all possible information and preferably a well schematic of the hole regarding the
hole conditions such as:
• Total depth
• True vertical depth
• Mud/brine type
• Mud /brine weight
• Maximum deviation
• Mud viscosity
• Depth to top of liner
• Cushion type
• Bottomhole temperature
• Maximum casing/liner test pressure
• Anticipated production rates.
2) Consult with the Mud Engineer about the performance of the mud/brine system under
conditions of static temperature and pressure for the anticipated duration of the test and
the compatibility of the mud/brine system to the cushion.
3) Confer with the Tool Pusher concerning testing requirements during the test, such as:
• Procedures for pressure testing and functioning equipment and the necessity of
doing this in a restricted area within easy access to air and water points.
• Pressure control and monitoring of the annulus. In particular, the presence of non
return valves in the rig manifolding needs to be discussed and how they can be
removed or bypassed. Potential tie-in points on the rig manifold for a pressure
monitor etc.
• Availability of handling equipment (e.g. lift subs, elevators).
• Procedures for picking up test tools.
10.6.3. Preliminary Inspections
The following preliminary inspections, shall be carried out before starting testing operation,
under the direct responsibility of the Company Drilling and Completion Supervisor who can
avail himself of Company Drilling Engineer (if Present) and drilling contractor personnel
(Toolpusher):
1) All tubular goods not required for the execution of the test and for the preparatory
operations (scraping, setting of bridge plugs, etc.), shall be laid down from the derrick
floor prior to start the test.
2) Fishing tools for all equipment to be used during testing shall be on rig.
3) Working area on the rig floor and around the separator, heater, tank and flare shall be
clear of obstructions and flammable substance.
4) An adequate platform shall be available to operate the valves on the flowhead.
5) Inspections shall be performed on masks, self breathing apparatus, resuscitators and
extinguishers in order to check their efficiency and location on the rig.

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
1) Electric installations placed within area classified as ‘hazardous’ shall be ‘explosion
proof’.
2) It shall be checked that all access doors and escape ways, fire doors and vent line
valves of pressurised tanks are in the position prescribed by the rig procedures during
‘production tests’.
3) Fuel tanks, oxygen bottles and other pressurised bottles shall be placed far from the
area classified as ‘hazardous’ and cooled with water, if necessary.
4) It shall be checked that the amount of water available to the burners water spray and to
the sprinkler system is sufficient to protect the burners and the rig from heat radiation
generated by the combustion.
5) Inspection shall be performed on anti-pollution equipment and chemical (dispersant)
stored on rig in order to cope with any oil spill which may occur, particularly during
formation clean out.
6) The accuracy of the data supplied by the anemometer (wind speed and direction) shall
be checked before opening the well.
7) Prior to start well testing operations, drills shall be performed for fire-fighting and
pollution prevention.
8) Inspection shall be made on operating conditions of the communication system among
rig floor, flares area and production equipment area.
9) Complete BOP test shall be carried out before starting well testing operations.
The following additional inspections shall be performed prior to start testing operations, under
the direct responsibility of Company Drilling and Completion Supervisor, who can avail
himself of production test equipment operators:
1) It shall be ascertained that the separator is equipped with safety valves (pop valves
and/or rupture plate outlets) in top operating conditions. The outlets of separator and the
vent lines of production tank(s) shall be free from obstructions and secured to fixed
structure of the rig. These lines shall usually be connected to the flares.
2) Inspections shall be carried out on the flares (blow-off lines), on the burners/flares
booms and on the burners igniting system.
For the ignition of burners/flares, a back-up system shall be available in addition to the
main fixed system.
A test on burners shall be performed using diesel oil as fuel.
An adequate supply of propane or butane should be available, if such fuel is used for the
igniting system.
Due to their dangerous nature, propane or butane bottles shall be stored in protected
area.
3) Each burner shall be capable of burning the whole amount of hydrocarbon produced,
that is to say their capacity shall be compatible with the maximum possible production.
Inspections shall be made on the water sprinkler system for the protection of the rig
from heat radiation in the area where burners are installed. In addition to this fixed
installation, special fire-fighting hoses with adjustable nozzles shall always be available
to cool any part of the rig that would happen to remain outside the protection of the
water sprinkler system.
10.7. PRE TEST EQUIPMENT CHECKS
1) Lay out the appropriate downhole tools, observing correct handling and slinging

ARPO
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Agip Division
REVISION
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procedures. Tools must be positioned in a manner so that they are secure and cause
minimal obstruction.
2) Visually inspect all tools to ensure no damage was sustained in transit particularly to
threads and sealing surfaces.
3) Function and pressure test tools according to procedures laid out in the service
companies operations manual which will be made available on the rig.
4) Ensure that all tool dimensions are accurately measured and lengths of extending
mandrels recorded etc.
5) Ensure all required crossovers have been sent and physically checked for correct
threads. Measure crossovers and note length, ODs and IDs. Particular attention should
be paid to the IDs of rented crossovers.
6) Ensure all tubulars are drifted, cleaned internally and the connections have been
inspected prior to running.
7) Lengths, ODs, IDs and thread connections of all downhole tools should be checked for
correct size and a list produced. All tools should be clean, free of any dirt or debris and
the connections cleaned properly on the rack. All crossovers should be properly
bevelled inside and out.
8) All downhole tools should be drifted to 2.125ins to allow running of surface read out or
any other wireline or coil tubing tool.
9) The pipe tester valve (PTV) should be made up to the packer on the deck and tested
from below to it’s working pressure prior to running in the hole.
10) A visual inspection should be made of the packer elements prior to running. The packer
should be set appropriately above the perforated interval to allow safe wireline
operations such as production logging, if required (i.e. ensure the bottom of the tailpipe
is positioned approximately 100ft above the top perforation).
11) The packer should never be set across a casing collar.
12) All downhole test tools should be pressure tested at surface to a minimum of 1,000psi
above maximum anticipated pressure.
13) A list of all pressure gauges and serial numbers should be compiled and submitted to
the Company Production Test Supervisor.
14) Only API 5A Modified thread lubricant should be used on tools, tubing and drill collar
connections.
15) The lubricant should be applied to the pin end only with a paint brush. Apply sparingly.
16) Check the brine weight as accurately as possible and ensure that it is correct, based on
the RFT results.

ARPO
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Agip Division
REVISION
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10.8. PRESSURE TESTING EQUIPMENT
All surface and downhole testing equipment shall be fully pressure tested prior to send to the
rig. Testing equipment shall also be pressure tested on the rig before starting a well test; in
particular:
1) For all pressure test, the area outside accommodation must be clear of non-essential
personnel.
2) Pressure tests shall be carried out using water. Each pressure test shall be recorded
on a record sheet and the pressure shall be held for a minimum of 15min.
3) Test pressures shall be specified on testing program. However, devices protected by
rupture discs should not be tested to more than 90% of working pressure.
4) BOPs, choke manifold, choke and kill lines shall be pressure tested as per Agip Well
Control Policy.
5) The following equipment of the surface package shall be pressure tested:
• To end of burners.
• To gas and oil diverter manifolds.
• Through test separator to outlet valves and bypass valves.
• To inlet valves and bypass valves on test separator.
• To outlet and bypass valve on heater.
• High pressure side of the heater up to blank choke and bypass valve.
• To inlet valves and bypass valves on heater.
• Two upstream valves on production choke manifold.
• Two downstream valves on production choke manifold.
The test shall be repeated whenever a connection on a line is broken out.
In case of long duration tests or in critical condition (presence of sand, H2S, etc.), the
opportunity of performing pressure tests at regular time intervals shall be evaluated.
Steam lines of the heater shall be pressure tested with steam according to manufacturer's
specification.
It is common practice to make up one full single joint of tubing from the landing string to the
flowhead in the rotary table and lay out the entire assembly on the pipedeck. This connection
must be done before running the test string as it cannot be torqued later due to being too high
when the string is finally landed.

ARPO
ENI S.p.A.
Agip Division
REVISION
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10.8.1. Surface Test Tree
The flowhead should be prepared on the catwalk in accordance to the contractors procedures
which should be as follows:
1) With master and swab valves open, drift the flowhead to it’s maximum diameter to
accommodate any wireline or coiled tubing tools to be run.
2) Function test the ESD actuator on the flow wing valve. The ESD is a fail-safe valve.
3) Make up one joint of the landing string to the flowhead with chain tongs.
4) After the SSTT and landing string dummy run has been made and has been racked
back in the derrick, pick up the flowhead with the single joint of tubing and torque it up in
the rotary table to the correct torque.
5) Check the torque on the swivel and any other flowhead service connection and then
paint a white band across them.
6) Ensure that the swivel is free to rotate completely in both directions.
7) Lay the assembly back down on the deck. Make up the test caps, complete with needle
valves, on all four outlet connections. Open all the flowhead valves and pressure test
the flowhead body from the bottom to test pressure
8) Close the swab, kill wing and flow wing valves. Open the respective needle valves in the
test subs downstream. Pressure test against the upper valves.
9) Close the upper master valve, open the kill wing valve and pressure test against the
upper master valve from below to test pressure.
10) Close the lower master valve, open the upper master valve and pressure test against
the lower master valve from below to test pressure.
11) Bleed off pressure below the lower master valve and leave the needle valve open. Open
the swab valve and pressure test against the lower master valve from above.
12) Close the upper master and pressure test from above.
13) Remove the test caps.
14) Clean and grease the connections.
15) Fit protectors and store the flowhead in a convenient place until ready to use.
The flowhead shall be pressure tested before installed it on the well with a tubing pup joint
assembled on bottom in the followed way:
1) Plug the kill side, the flow side and close the swab valve; pressure test the internal of
flowhead pumping through the pup joint.
2) Bleed off pressure and remove plugs from kill and flow side, close kill valve ,flow side
fail-safe valve and pressure test the gates from inside.
3) Close master valve and bleed off the down stream pressure to pressure test the gate
from below.
This procedure may be adjusted to the actual flowhead configuration.

ARPO
ENI S.p.A.
Agip Division
REVISION
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Figure 10.C - Flowhead Schematic

ARPO
ENI S.p.A.
Agip Division
REVISION
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11. TEST STRING INSTALLATION
Detailed individual well programmes will be issued for all wells to be tested, which includes
development, appraisal and exploration wells.
Each programme will include contents, the exact details of which will be well specific
dependent upon the well status and expected well parameters. The following is the contents
of a typical test programme.
a) Test Objectives.
b) General well data and perforating details.
c) Summary of test programme.
d) Guidelines for liner lap test and space-out calculations.
e) Sequence of operations for running downhole tools and surface equipment rig up.
f) Flowing procedures for each test conducted.
Also included will be the following, possibly as appendices:
• Hole cleaning and displacement to brine procedure.
• Stimulation programme (if applicable, e.g. coil tubing rig up).
• Sampling requirements.
Detailed string diagrams and equipment layout diagrams will be included, as well as all
relevant pressure testing procedures and equipment ratings.
11.1. GENERAL
a) The testing string shall normally be made up of tubing. The use of drill pipe is only
allowed in limited fluid entry test (DST).
b) All equipment and material used in production tests shall be H2S service.
c) Governmental bodies charged with the control of drilling activity and/or other state
agencies shall be notified, if required, on test execution with advanced notice.
d) Before starting and upon completion of flaring operations, company shall give notice to
competent authorities.
e) Prior to the start of casing perforating, visitors and non essential personnel shall leave
the rig and rig personnel shall be limited to the minimum.
f) Prior to start well testing operations a meeting shall be held by wellsite Company Drilling
and Completion Supervisor and Drilling Contractor Toolpusher to make all personnel
involved are acquainted with detailed operating program (procedures and rules).

ARPO
ENI S.p.A.
Agip Division
REVISION
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11.2. TUBING HANDLING
a) Tubing must always have the pin and box protectors in place while being handled.
b) Tubing should always be handled with either certified nylon or cable slings or with
single joint elevators when picking up or running out the tubing from the Vee door.
Never Use Hook Ends
c) Avoid rough handling of the tubing which may damage the joint.
d) Never allow the tubing to be dropped when loading and or moving.
e) Never bundle tubing in greater quantities than ten.
f) Tubing joints will be supplied in singles with protectors fitted and should be laid
down on deck in even layers, no more than 10 levels high.
g) After removing the protectors, the connections should be thoroughly cleaned and
inspected after drifting. One of the following Agip approved methods of cleaning
should be used:
• Use of non-metallic brush and a recommended solvent.
• Steam clean using a high pressure jet of steam and solvent.
• A rotary bristle brush jetted water and cleaning solvent.
h) The pins and boxes should be visually inspected for any damage by a qualified
Tubing Inspector.
i) Reject and damaged joints should be painted red and documented and then
returned to the onshore base for remedial work if necessary.
j) The tubing should then be drifted/measured, and each joint numbered in the
middle of the joint with white paint and strapped and tally recorded (drift the pipe
box to pin at all times).
k) After the threads have been cleaned and inspected it is important they be
protected from corrosion. Never leave the threads for longer than two hours
without corrosion protection.
l) If the connections are cleaned more than two hours but less than 12hrs prior to
the joint being run, then a light oil should be used to prevent corrosion. If it is to be
longer than 12hrs then a light film of dope and protectors should be reapplied.

ARPO
ENI S.p.A.
Agip Division
REVISION
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11.3. RUNNING AND PULLING
a) Any protective coating which has been applied to the tubing for storage should be
cleaned off before the tubing is run for a DST. This can probably be done most
conveniently during the procedures for casing cleaning and displacement to brine.
With the tubing string in the hole, proprietary cleaning fluids can be circulated to
remove the coating material.
b) Ensure all accessories/tools are on the rig floor and are in prime condition ready
to run the tubing, i.e. pup joints, crossovers, stabbing guides, single joint
elevators, modified pipe dope, dog collar, slip type elevators.
c) Ensure the safety clamp (dog collar) is correctly sized ready for the 41
/2” tubing
(the dog collar should be used above the rotary table slips until the first 20 joints or
until the Company Production Test Supervisor thinks enough weight is available to
properly set slips.
d) Slip type elevators to be used at all times. Check the elevator setting plate for
proper operation. This will ensure the elevators set on the body of the pipe, not on
the upset or connection area.
e) Check the alignment of the rotary table and the elevators.
f) During make-up, the tubing must be allowed to spin freely, which may necessitate
slacking off on the blocks until the weight is off the elevators.
g) Use power tongs and integral hydraulic back-up for all make-up and break-outs at
recommended optimum torque valves. The use of a torque/turn analysis system,
such as Weatherford’s ‘Jam’ system, is recommended.
h) The power tong lead line should be attached to a back-up post and should be
labelled. Ideally the angle with the tong arm should be 90o
.
i) When pulling the tubing, always use a wiper rubber.
j) Always install the pin protector fully before standing the tubing in the derrick.
k) Never use a sledge hammer on connections to assist the break-out.
l) Ensure tubing set back in the derrick is properly supported with a belly band to
prevent undue bending.
m) Always use the manufacturers recommendations for running, pulling or make-up.
n) Check that the calibration of the torque machine is valid.
o) A tubing inspector or the Company Production Test Supervisor must be on the rig
floor witnessing the make-up of all the joints that make-up the test string.
p) If there is insufficient space in the derrick to store both drillpipe (51
/2”, 31
/2”) and
tubing, then lay down drill pipe in preference.

ARPO
ENI S.p.A.
Agip Division
REVISION
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11.4. PACKER AND TEST STRING RUNNING PROCEDURE
Before running the test string all the earlier procedures should have been carried out to
prepare the well, tubing and tools for the test. The procedure for running the test string will
vary depending upon the equipment used.
The main difference in running the string is due to the type of packer being used and whether
it is from a floater or a Jack-up rig. Example test string running procedures are given below for
running strings with both types of packers from a semi-submersible drilling unit. For a Jack-
up, the SSTT would be replaced by the sub-surface safety valve.
The specific running procedures will always be detailed in the well specific test programme.
11.5. RUNNING THE TEST STRING WITH A RETRIEVABLE PACKER
1) Run a junk basket on wireline to below the packer setting depth.
2) Before running the test string, hold a brief safety meeting on the drill floor and re-
emphasise the precautions that should be taken during operations.
3) Ensure a Kelly Cock is situated on the drill floor for emergency use.
4) The downhole gauges should be programmed and installed into the gauge carrier(s) in
advance.
5) Make up and run the TCP gun assembly.
6) Install the packer assembly as per the string diagram.
7) Continue making up the string using a back-up tong to ensure that the packer is not
turned to the right.
8) Pick up the test tools in reverse running order and make them up to the correct torque.
Care should be taken that no connections are backed out and that the packer is not
turned to the right.
9) Run the tools into the well and make up the crossover and first joint(s) of intervening drill
collars.
10) Ensure the BOP blind rams are open before the test tools reach them.
11) Continue running the minor string as per the string diagram, until all the collars and slip
joints have been made up. Note the string weight.
12) When the first tubing joint of the major string has been run, pressure test the minor
string.
13) Run the tubing.
14) When the test string has been run half way into the well, the tubing should again be
pressure tested (optional).
15) If there is a liner hanger above the packer setting depth, run the tailpipe and packer
through the liner hanger slowly.
16) When all major string has been run, it is recommended that the string should again be
pressure tested.
17) Pick up the SSTT assembly and make up to the tubing and function test.
18) Continue running the landing string, strapping the SSTT hoses to the tubing.
19) Install the lubricator valve.
20) Continue running the landing string and the space-out pup joints, strapping all hoses to
the pipe.

ARPO
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Agip Division
REVISION
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21) Install the surface test tree and 50ft bails or CTU lifting frame.
22) Run a GR/CCL log to verify the packer setting depth. (Refer to appropriate section
according to gun type).
23) Set the packer and set down weight until the fluted hanger lands out in the wellhead.
24) Set the packer and set down weight until the fluted hanger lands out in the wellhead.
25) Run a GR/CCL log to verify the packer setting depth. (Refer to appropriate section
according to gun type).
26) Carry out the hook-up and final pressure testing.
27) The well is now ready to be perforated and tested.
11.6. RUNNING A TEST STRING WITH A PERMANENT PACKER
1) Run a junk basket to below the packer setting depth
2) A safety meeting should first be held on the drill floor.
3) If the TCP guns are being run below the packer, make up the TCP gun assembly.
4) Install the packer and packer tailpipe assembly as per the programme. The packer
should be spaced out so that it is at least 5ft away from a casing collar.
5) Run the packer/TCP assembly on drillpipe with a radioactive marker sub, one stand
above the setting tool.
6) Open the blind rams before the test tools reach them.
7) Rig up and run a GR/CCL and correlation gun setting depth.
8) Rig down the wireline. Adjust the setting depth as required.
9) Set and pressure test the packer. Pull the work string.
10) Ensure a Kelly Cock is situated on the drill floor for emergency use.
11) The downhole gauges should be programmed and installed into the gauge carrier(s) in
advance.
12) If the TCP guns are to be run on the string, make up the gun assembly.
13) Install the space out tubing and then the seal assembly.
14) Continue and pick up the DST tools in reverse running order and make them up to the
correct torque. Care should be taken that no connections are backed out.
15) Continue running the minor string as per the string diagram, until all the collars and slip
joints have been made up. Record the string weight.
16) When the first tubing joint of the major string has been run pressure test the minor
string.
17) Run the tubing.
18) When the test string has been run half way into the well, the tubing should again be
pressure tested (optional).
19) If there is a liner hanger above the packer setting depth, run the end of the string slowly
through the liner hanger.
20) When approaching the permanent packer, pick up by one tubing joint to check the up
weight and slack back down to check the down weight.
21) Run in slowly and tag the packer. Mark the pipe and calculate the spacing out.
22) It is recommended that the string be pressure tested.

ARPO
ENI S.p.A.
Agip Division
REVISION
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23) Pull slowly out of the packer and pull back the pipe to install the SSTT.
24) Space out and pick up the SSTT assembly, install onto the tubing and function test.
25) Continue running the landing string, strapping the SSTT hoses to the tubing.
26) Install the lubricator valve.
27) Continue running the landing string, strapping all hoses to the pipe.
28) With the seal assembly still out of the packer, install the surface test tree attached to
the final joint. Rig up the 50ft bails or CTU lifting frame.
29) Carry out the hook-up pressure test.
30) Slowly lower the seal assembly into the packer and land the SSTT hanger.
31) Conduct the final string pressure tests.
32) The well is now ready to be perforated and tested.

ARPO
ENI S.p.A.
Agip Division
REVISION
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12. WELL TEST PROCEDURES
12.1. ANNULUS CONTROL AND PRESSURE MONITORING
An important aspect of any well test is the continuous monitoring of the annulus pressure.
This responsibility shall be delegated to the Driller who will maintain a log of pressures and
tool functioning throughout the test.
The well conditions during flow periods will affect the temperature and, therefore, the fluid
volume in the annulus. These temperature effects should be closely monitored and pressures
adjusted throughout the flow period by the Driller to keep them within the parameters given by
the DST specialist.
Note: Annulus pressure should always be controlled by the rig choke manifold.
and any hydrocarbons vented to the poor-boy de-gasser.
The following aspects for annulus monitoring must be planned beforehand:
• At least two independent measurement points should be made available so that a
comparison of the two can be made at regular intervals.
• Two bleed-off/top up ports should be available to bleed down/top up the pressure
from the thermal expansion/contraction.
• The monitor should be tied into the surface data gathering system.
• A test tool operator should be present on the drill floor at all times to advise the
Driller of the test tool parameters and optimum operating pressures.
• It is important that the Driller maintains a frequent check and records all bleed off/
top up times and volumes.
12.2. TEST EXECUTION
a) Welding, cutting and any other operation involving the use of open flame shall be
forbidden, unless express, nominal written permission is given and signed by the
Company Drilling and Completion Supervisor and Drilling Contractor Toolpusher.
b) A suitable amount of mud shall be available during casing perforations and formation
testing. The amount of mud shall be 1,5 times the volume of the well.
c) Mud pumps shall be lined up to reserve mud and all relevant valves from the pumps to
the flow head's kill line should be in open position.
d) The test string shall include as a minimum the following downhole and surface
equipment (from bottom to surface):
• Tailpipe
• Packer
• Safety joint
• Jar
• Tester
• Two reverse circulation valves
• Slip joints
• Flowhead.

ARPO
ENI S.p.A.
Agip Division
REVISION
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a) Initial opening and/or initial flow through separator shall be carried out in daylight only. All
subsequent flow/build-up operations can be performed at night under favourable
weather conditions.
b) Wind speed and direction shall constantly be monitored before formation clean out and
during the flow to avoid smoke vapour, gas and heat invading the rig.
To this purpose, Company and Contractor personnel shall continuously and directly
monitor the flame behaviour at the flares to be able to intervene in case of sudden
changes in wind direction.
g) Initial opening shall be avoided in windless condition. The decision to suspend a test
due to windless conditions shall be taken by Contractor's Toolpusher after consultation
with Company's Drilling and Completion Supervisors.
h) The test shall be suspended whenever the normal course of operations is hampered or
drilling unit's safety is jeopardised (heating of the structures, presence of smokes, gas
on the rig).
i) Wireline operations inside a test string shall be limited as much as possible.
j) Downhole pressure build-up (shut-in) shall be obtained by closing the tester valve.
k) Well shut-in at the surface shall only be limited to extreme case.
l) Upon flow beginning, the presence of H2S into the formation fluid shall be detected as
soon as possible.
If H2S is present, procedures to operate in sour gas contaminated environments shall
be strictly observed (Refer to the Drilling Procedures Manual).
Frequent test on H2S presence shall be carried out on the rig floor, production
equipment and flares area, near pumps and engines.
Any indication of H2S presence shall immediately be notified to Contractor's Toolpusher
and Company's Drilling and Completion Supervisor.
m) It is forbidden to release to the atmosphere non-combusted hydrocarbons.
Only the use of production stock tanks shall be allowed.
n) All stimulation jobs and subsequent formation clean out operations, shall be performed
in daylight.
o) During acid jobs, at least two water hoses shall be available to dilute any possible acid
spills.
p) During acidizing, surface pressure’s shall not exceed the surface equipment testing
pressure or the working pressure of the weakest joint of the test string, whichever is
lowest.
q) During acid job must be definite and marked all the pressure areas.

ARPO
ENI S.p.A.
Agip Division
REVISION
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13. WELL TEST DATA REQUIREMENTS
13.1. GENERAL
The following is the procedure for gathering well test data:
1) Monitor all data points with the electronic surface data acquisition system as shown in
table 13.a.
2) Take manual separator and manifold readings every 30min during the well test and as
directed during clean-up.
3) Flow to the gauge tank for liquid flow rates and meter calibration.
4) Take manual H2S and CO2 Draeger readings every hour during the clean-up.
5) Maintain detailed records on all well flow characteristics and operational changes with
description, e.g. ‘fluid to surface’, ‘direct flow to test equipment’ etc.
6) Take BS&W samples every 30min and the mud logger is to perform laboratory analysis
of water for chlorides and any other ions such as Ca, Mg, sulphates, TDS, pH and
density.
7) Record the specific gravity of the gas, oil and condensate every 30min.
8) Take pressurised combination gas, oil or condensate samples from the separator for
every main flow period for PVT analysis or as required by the Reservoir Engineer. Make
detailed records and complete the sample forms to give type of sample, well
parameters, at sampling time, time sample take, bottle numbers etc. Dispatch all PVT
samples immediately for analysis.
9) Collect other fluids samples as detailed in the Well Testing Programme. Dispatch these
to the district warehouse for storage until their disposition is decided.
10) During a water test, collect water samples every hour during clean-up and stable flow
periods and perform onsite analysis, initially to monitor clean-up from contaminated to
true formation water and then to confirm the continued production of clean formation
water. Onsite analysis is to be conducted to check for chloride and equivalent sodium
chloride levels, sediment, resistivity, pH, total dissolved solids and specific gravity.
11) Collect samples of true produced formation water in plastic or pressurised containers,
as instructed by the Reservoir Department for laboratory analysis. Dispatch as per step
6) above.
12) Foreign or unidentified materials produced from the well should be kept in a marked up
plastic sample packet for onshore analysis.
13) All samples must be clearly identified and logged.
14) In addition to Draeger readings and, if required, monitor constantly for CO2 and H2S
presence throughout the test using Orsat (UOP 172/59) and cadmium sulphate titration
(ASTM D2385).
15) Monitor sand production by sand detection system and take samples as necessary.
16) Take manual pressure and temperature readings upstream and downstream of the
choke, initially every five minutes, during the clean-up.
17) Monitor bottomhole flowing and shut-in pressures and temperatures with surface
readout system as appropriate.

ARPO
ENI S.p.A.
Agip Division
REVISION
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13.2. METERING REQUIREMENTS
Prior to the commencement of testing, the separator flow meters and Barton differential
pressure recorder should have been calibrated.
All personnel involved in the operation of metering devices and gauges must keep a detailed
log of the test sequence, as this is very important to the final interpretation of the test data.
A surface data acquisition system should be utilised permitting more frequent data collection.
However, if for any reason this system is not utilised, the recording intervals of table 13.a shall
apply.
Note: These intervals may be altered at the discretion of the well site Company
Production Test Supervisor.
Readings Timing
1 Well Pressure 1st Flow Every 1 min for 10 mins
Every 2 mins for 20 mins
Every 5 mins until end
Further Flow Periods Every 5 mins for 1 hour
Monitor THP during build up in case tester valve is leaking
2 Wellhead Temperature 1st Flow as above
Further Flow Periods as above
3 SRO Pressure and
Temperature
(Print-outs)
Further Flow Periods Every 15 secs for 10 mins
Every 1 min for 20 mins
Each build up Every 15 secs for 15 mins
Every 1 min for 45 mins
Every 5 mins until end of build up
4 Separator Flow Rates Every 30 mins
5 Shrinkage Every 2 hours
6 Oil and Gas Gravities Every 1 hour
7 BS&W As frequent as possible to determine if sand is
being produced
8 H2S Determination 1st Flow As frequent as possible with detector tubes at
choke manifold bubble hose
Further Flow Periods Every 2 hours by chemical analysis of separator
gas
9 CO2 Determination As for H2S
10 Downhole Memory Gauges Minimum 4 gauges, preferably 6-8 gauges, to be
run. Minimum 2 different types of gauge to be run.
Seek advice from Reservoir Engineers during test
planning for special requirements.
Table 13.A- Data Gathering Timings

ARPO
ENI S.p.A.
Agip Division
REVISION
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13.3. DATA REPORTING
Second only to safety, the task of data gathering and reporting is the most important activity
during a well test and is the prime responsibility of the Company Production Test Supervisor.
The data will generally be recorded by the service companies, but it is the responsibility of the
Company Production Test Supervisor to ensure it is collected correctly, accurately and then
distributed.
13.4. PRE-TEST PREPARATION
After the test programme has been finalised, the following points should be discussed with
the participating service companies:
a) The type of downhole gauges to be run taking into consideration the range of
pressures and temperatures to be encountered, the planned length of the test and
the accuracy required. The responsibility for onsite interpretation of data should
also be decided.
b) The range of surface flowrates expected should be discussed so that the correct
instruments and orifice plates can be selected. The frequency of data
measurement and the report presentation should also be decided, if a
computerised data acquisition unit is to be used.
c) The frequency and locations to take samples for fluid identification during the test
should be decided. These include samples for water, sand and H2S production.
Responsibility for onsite analysis of samples should also be determined.
d) The schedule for sampling for retention should also be discussed.
e) The Well Testing Contractor must submit their Safety Procedures Manual for
approval.
13.5. DATA REPORTING DURING THE TEST
Data collected during the well test will be reported in the following formats, in addition to the
daily drilling reports:
a) Company Production Test Supervisor’s reports:
• Daily Telex of summary of operations
• Detailed Daily Diary of operations prepared daily by Company Production
Test Supervisor on the rig and eventually returned to shore for placing in the
well file.
b) Composite data acquisition system report (if used)
c) BHP gauge contractor’s reports (both hard copy and on compatible 5.25ins disk)
d) Surface test facilities contractor’s report
e) Sampling contractor’s report (downhole sampler)
f) Stimulation contractor’s report (if used)

ARPO
ENI S.p.A.
Agip Division
REVISION
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13.6. COMMUNICATIONS
(Also refer to the Company ‘Drilling Procedures Manual’.)
During the course of the test, it is important that information flows freely from the rig to the
onshore base. The following telexes should be sent to the base to reduce the risk of
misunderstanding and ensure a smooth operation.
• A daily telex should be prepared on the rig for transmission in the morning
covering the last 24hr period ending at 24.00hrs. This should be on the desk of
base personnel when they arrive in the morning and will be used to keep partners
informed. An afternoon telex should also be prepared covering the period to
15.00hrs. These telexes should include operations on an hour-by-hour basis with
details of tools run in hole, flowrates, pressures etc.
• A telex should be sent at the end of each test briefly summarising the daily
operations and main results of the test. This is a ready source of data on the test
which may be used for parent Company reports and reports to partners.
• Samples taken during the test should be sent to shore as soon as the test has
been completed. A telex should be sent listing all the samples, the boat used for
transportation when the boat leaves the rig and the ETA. If offshore, do not
send all the samples taken during a single test on the same boat; split
samples into complete sets and dispatch on different vessels.
If any changes are to be made to the programme during testing operations, a telex or fax will
be sent from the rig to the base summarising the procedure that is proposed to be followed
for the next sequence of operations. This should be accordingly approved by shore base
Production Superintendent who will ensure that all relevant personnel are informed of the
change in the programme.

ARPO
ENI S.p.A.
Agip Division
REVISION
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14. SAMPLING
14.1. CONDITIONING THE WELL
The well should be conditioned prior to sampling to ensure representative reservoir fluids are
being produced.
The well should be flowing in a stable state, with correspondingly stable separator readings
for at least 6 hours before the start of any sampling. The stability of the well may be
determined by:
• Gas and Oil flow rates
• GOR
• Wellhead pressure
• Downhole flowing pressure.
If the above measurements are stable then the well may be considered ready for separator
sampling.
Care should also be taken to ensure the well flow rate is in excess of the minimum at which
liquid fallback in gas wells occurs, otherwise surface samples will not be representative. This
rate is dependent mainly upon the GLR and the tubing size.
If the well has been perforated close to the gas/oil contact, samples may be invalid and
should probably not be taken.
Surface sampling can be undertaken if the well is producing water but downhole sampling is
not recommended.
14.2. DOWNHOLE SAMPLING
After the well has been conditioned, it should be either shut-in or left to produce at a very low
flow rate. At least two bottomhole samplers in conjunction with a pressure and temperature
gauge are installed in the well on wireline. A short pressure and temperature gradient survey
must be performed above the sampling point e.g. at five different depths with 100ft intervals.
This is to determine whether the sample taken will have been in single phase, i.e. below the
level at which gas may be breaking out of solution, or above the OWC. Ideally, the sampling
point should be above the perforations. When the samplers are on depth, the samples are
taken and the pressure and temperature at the sampling depth will be recorded by the gauge
at this time.
Samplers are either actuated mechanically by a clock or electrically by a signal from surface.
If clock-type samplers are used, the samplers should be placed on depth before the
scheduled actuation time for some period of time to allow for clock inaccuracies.
The samplers are then pulled out of the hole and the samples transferred into the
shipping/storage bottles. The quality of each sample should be checked by bubble point
determination. It is recommended that at least two runs are made with two samplers each run
and that at least one sample is transferred at 100o
F using a heating element. If possible, each
sample should be transferred similarly to ensure that no wax is left on the wall of the
container. If not, this sample should be marked separately.

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Depending on conditions, sampling should continue until consistent quality checks are
obtained on two separate samples.
Note: All sampling should utilise mercury-free systems and piston type sample
bottles for safety of personnel.
For long term storage of Agip samples, all well effluent samples should be transferred to
Teflon lined bottles and the mercury-free bottles returned off rental.
14.3. SURFACE SAMPLING
14.3.1. General
Surface samples are taken after the well has been conditioned for later recombination in the
laboratory. Gas and oil samples should be taken simultaneously forming paired or
‘companion’ samples. It is important that accurate gas and oil production rates are known at
the time of taking the samples. Refer to API RP44 for further details.
Before any separator sampling begins, the following procedures should be carried out:
1) Sample bottles should be made ready by having the gas bottles checked to ensure that
they have an absolute vacuum and plugs available for each port.
2) Oil sample bottles need to be checked to ensure they are evacuated above the piston,
and that the piston is at the top of the bottle. The fluid below the piston should be
checked to make sure that there is no air present, as this can give extraneous readings
when measuring the fluid flow whilst sampling is in progress. This will cause problems
later when an attempt is made to determine the pressure (Pb) in the PVT laboratory.
3) The sampling manifolds should be prepared with gauges to suit the expected sampling
pressure already fitted. Liners should be cleansed and made ready. An oil sample bottle
stand should be readily available, together with a 600cc measuring cylinder. Sampling
manifolds should be kept as simple as practically possible with as small an internal
volume as is reasonably possible but with liners that are long enough to avoid any
possibility of straining the connections to the sampling point and to the sampling
manifold.
4) A bucket of clean water and a supply of rags should also be readily available for leak
testing full sample bottles and for wiping clean the bottles before shipping to the PVT
laboratory.
5) For gas, sampling should be conducted using evacuated sample bottles. These are
clean and easy to use as no flushing is required, hence contamination is unlikely. A
vacuum pump is required and care should be taken that no valves become plugged with
hydrates.
6) Oil should be sampled using piston bottles. These are clean, easy to use, have a known
volume and are mercury-free. They are also relatively easy to use in forming the gas
cap for safety during transportation.

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7) All samples must be labelled immediately after being taken using Agip sample labels, if
available. The following information must be recorded:
• Well number.
• DST number.
• Choke size.
• Perforation interval.
• Time of sampling and duration.
• Oil/condensate and gas rate at time of sampling.
• Stock tank oil/condensate, temperature, gravity and shrinkage, pressure.
• Gas temp, gravity, static and differential pressures, orifice size and meter run
size.
• BS&W.
8) All samples should be loaded into an empty container and shipped to base as soon
after the test as possible. Record on the morning report, the container in which the
samples are being shipped to shore. Do not ship all samples in one container, split
samples into two representative batches and ship in separate containers.
9) It is vital when taking samples that any problems are recorded, highlighted and fully
documented.
Note: More specific sampling requirements may be detailed on individual well
testing programmes.
14.3.2. Sample Quantities
Separator samples should always be taken simultaneously as matched sets of oil and gas
samples, thus being sampled under identical conditions. At least two sets of separator
samples (2 x oil and 2 x gas) should be taken, so that there is comparability between sets of
samples. The ratio of gas samples to oil samples is dependent upon the GOR - hence being
one of the reasons stable separator conditions is required.
GOR equal or less than 1,500scf/stb = 1:1
GOR greater than 1,500scf/stb, but less than 3,000scf/stb = 3:2
GOR greater than 3,000scf/stb = 2:1
14.3.3. Sampling Points
The sampling points on a separator should be very carefully chosen as samples taken from
the wrong point on a separator will not be truly representative of the produced fluids.
The gas sample point should be:
• Upstream of the Daniels box in the gas line.
• As close to the separator vessel, as possible.
• Not immediately downstream of thermal wells or ports in the flowline.
• Not immediately after a bend in the flowline.
• Ideally the sampling point should protrude into the centre of the gas flowline and
face upstream. However, a pipe into the stream is acceptable.
Note: The sampling point should not be on the lower half of the flowline cross

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section, due to any possibility of free liquid/liquid carryover being
present. If the sampling point has to be fitted flush to the inside surface
of the flowline then it is preferable that it is on the top of the line and not
on the side.
The oil sampling point should be:
• As close as possible to the exit of the oil flowline from the main vessel and
upstream of meters.
• Not immediately downstream of thermal well or bends in the flowline.
• Ideally the sampling point should protrude into the centre of the flowline with the
mouth facing upstream. However a pipe into the centre of the flowline is
acceptable.
• It should be upstream of any increase in flowline diameter.
• It is preferable that samples are not taken from the bottom of the oil sight glass,
as the level in the sight glass does sometimes falls, especially if there is much rig
movement which can allow free gas to enter the sampling line.
Note: The sampling point should not be on the upper half of the flowline cross
section, due to any possibility of there being free gas. If the sampling
point is on the wall of the flowline then it is preferable that it is on the
side, rather than on the top or the bottom, due to possibility of free gas or
water being in the flowline.
14.3.4. Surface Gas Sampling
The following is the procedure for taking a gas sample:
1) Any flushing should be done through a hose directly downwind, or to sea level, to
prevent any risk of poisoning due to gasses such as H2S.
2) Record the bottle number.
3) It is preferable, for the sake of safety, to take gas samples with the bottles lying
horizontally unless it can be securely fastened upright or held in a stand.
4) The manifold should be flushed before use, then attached either to the top valve (V1), or
to one of the end valves (V1, V2) if the bottle is lying on its side (Refer to figure 14.a).
The manifold valve (V3) should then be opened slowly to test for any leaks. If there is a
leak, then close the manifold valve, and remake the connections to the bottle.
Note: No manifold or gauge should be attached to the second valve (V2) under
any circumstances. This is to prevent the loss of any of the heavier
components of the gas which might have condensed in the bottle when
exposed to a vacuum.

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5) The bottle valve (V1) may now be slowly cracked open. Even with the noise around a
separator, it is still quite easy to hear the gas ‘hissing’ into the bottle and this can also
be heard even when wearing a BA set. Sometimes the gauge needle can be seen to
slightly dip on the initial opening.
If there is just one gas bottle being filled to one oil bottle, then the sampling time should
be about 30 minutes. This length of time means there is less chance of an invalid
sample being taken.
If the ratio of gas samples to oil samples is greater that 1:1, then the fill time should be
worked out to still allow the oil samples to take about 30 minutes.
6) When the sample bottles are full and the sampling time has elapsed, shut the bottle
valve (V1) and the valve on the separator sampling point (V3).
7) Record the pressure on the gauge, and bleed off about 30psi (using V4) then open the
bottle valve (V1). The gauge should now read the original sampling pressure. If it doesn’t
then check the manifold and the bottle valve for blockages or icing-up. If possible clear
the obstruction, take up a fresh bottle, and re-sample both the oil and gas samples. If
the pressure returns to near the original, then the sample is good and the separator
sampling point valve (V3) may be reopened for a few moments to allow the pressure in
the bottle to return to the sampling pressure.
8) Record the final sampling pressure and temperature, as they will be needed for the
sampling sheets. The bottle and manifold valves (V1, V3) may now be closed, and the
connecting line broken.
9) Plug the valves, and both valves checked in a bucket of water for any leaks. Now place
the bottle safely aside.
10) Prepare for the next bottle for sampling.

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14.4. SURFACE OIL SAMPLING
The following is the procedure for taking an oil sample (a piston sample bottle is the preferred
option for liquid sampling):
1) First record the bottle number.
2) The piston sample bottle should be stood in its custom built stand provided for the
purpose.
3) The top manifold should be flushed to ensure that the line to the manifold and the
manifold filled with fresh fluid from the flowline.
4) The manifold may now be connected to the top valve (V1) on the sample bottle.
5) Connect the lower manifold to the bottom of the sample bottle, open the bottom bottle
valve (V2) and use the pump to pressurise the bottle below the piston to a pressure
slightly in excess of the sampling pressure. This stops the piston moving as soon as
the bottle top valve is opened, so preventing any oil from flashing into the bottle. It also
acts as a double check to ensure that the piston is still at the top of the bottle.
6) The next step may be performed in one of two ways:
• Open the top manifold valve (V3), then connect a flushing line to the evacuation
port (V6) on the sample bottle. Open the top bottle valve (V1 to allow oil into the
top of the bottle) and slowly crack open the evacuation port (V6). This flushes the
initial flow of oil and gas which flashed into the bottle. Flush approx. 50cc of fluid
then close the evacuation port (V6). Remove the line and refit the plug, ensuring
that it is tight.
• Connect a vacuum pump to the evacuation port (V6) and check that there is still
an absolute vacuum. Ensure that the top manifold valve (V3) is closed. Open the
top bottle valve (V1) and evacuate the short line from the top manifold (V3) to the
top bottle (V1) valves. Close the top bottle valve (V1) and the evacuation port (V6).
Remove the vacuum pumps, and refit the plug ensuring that it is tightly in place.
Open the top manifold valve (V3) slowly. Now open the top bottle valve (V1)
slowly and fill the crown of the piston. Place the tube from the bottom manifold
into the top of a measuring cylinder, and slowly crack open the bottom bottle valve
(V2). Now slowly crack open the flow regulating valve (V5), so as to take 30
minutes to collect a 600cc sample (20cc /minute).
7) Remember that this sample must be taken in conjunction with the gas sample.
8) When the sample bottle contains 600cc of separator fluid, close the flow regulating
valve (V5). Shut the top bottle (V1) and manifold valves (V3). Bleed off and disconnect
the top manifold from the bottle and plug the top bottle valve (V1).
9) The sample is now consolidated.
10) A gas cap should now be formed to permit the safe shipping and storage of the bottle.
This is done by removing a portion of the buffer fluid equal to 10% of the sample
volume. This is called the Ullage.
11) The final pressure and temperature should now be recorded. This is vital for the
laboratory as it informs them what conditions to expect when they analyse the sample
and how much buffer fluid to inject to enable them to match the sampling conditions.
12) The bottom bottle valve (V2) should now be closed and the pressure in the bottom
manifold valve bled off before removal.

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1) Fit a plug to the bottom valve (V2). Check the integrity of the valves and plugs by
immersing the bottle in a bucket of water and checking for bubbles. Remove from the
water, dry the bottle and fit the protective end caps.
2) Now place the bottle in its box and set aside.
3) Prepare the next bottle for sampling.
14.5. SAMPLE TRANSFER AND HANDLING
Detailed instructions on shipment of samples from the rig, shore addressee(s) for the
samples, location of temporary and/or permanent storage facilities and instructions on
subsequent analysis of samples will be included in the Well Test Programme, or issued with
separate instructions.
Figure 14.A- Surface Sampling Typical Installation

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14.6. SAFETY
All equipment must be pressure tested and appropriately certified prior to dispatch.
Obtain and comply with any permit to work system before commencing any work.
14.6.1. Bottom-hole Sampling Preparations
Workscope Pressure testing and priming the tools with synthetic oil.
Work Area Rope off the work area and post pressure testing signs. Inform all
relevant personnel before commencing, and after completing,
pressure testing. All non-essential personnel are to be kept clear.
Safety Gear Safety glasses and gloves must be worn.
Comments Tools will now contain high pressure dead synthetic oil and should
be stored and moved in a safe manner.
14.6.2. Rigging Up Samplers to Wireline
Workscope Attaching the samplers to the running toolstring.
Work Area Rig floor and wellhead area.
Safety Gear Additional gear may be required depending on mud type.
Comments Normal slickline/electric line safety procedures are to be followed.
The tools will now contain high pressure dead synthetic oil and no
pipe wrenches are to be used on the tool. The sampling engineer
will supervise the tool handling.
14.6.3. Rigging Down Samplers from Wireline
Work Scope Removing the samplers from the running toolstring.
Work Area Rig floor and wellhead area.
Safety Gear Safety glasses and gloves must be worn; additional gear may be
required depending on type of mud.
Comments Normal slickline/electric line safety procedures are to be followed.
The tools will now contain high pressure oil/gas samples and no
pipe wrenches are to be used on the tool. No source of ignition is to
be in vicinity. The sampling engineer will supervise the tool
handling.

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14.6.4. Bottomhole Sample Transfer And Validations
Work Scope High pressure transferring and validation of sub-surface samples
from tools to high pressure storage cylinders.
Work Area Indoors, well lit with a 100psi air supply, stable temperature and
away from any sources of ignition. Rope off the area and post
pressure testing signs. Inform all relevant personnel before
commencing, and after completing, transfers or validations. All
non-essential personnel are to be kept clear.
Safety Gear Safety glasses and gloves must be worn.
Comments When high pressure oil/gas samples are transferred from tools to
cylinders, leaks are highly unlikely but possible, thus there must be
no sources of ignition in vicinity and no non-essential personnel in
area. If H2S in present, normal H2S operating procedures are to be
followed, i.e. breathing apparatus, buddy system etc. Personnel
work duration will not generally exceed 18hrs.
14.6.5. Separator/Wellhead Sampling
Work Scope High pressure transferring of hydrocarbons from separator to high
pressure storage cylinders.
Work Area Well test area and rig floor. Rope off the area and post pressure
testing signs. Inform all relevant personnel before commencing,
and after completing, sampling. All non essential personnel are to
be kept clear.
Safety Gear Hard hat, boots, coveralls, safety glasses, ear protection and
gloves must be worn.
Comments When high pressure oil or gas samples are obtained, leaks are
highly unlikely but possible, thus there must be no sources of
ignition in vicinity and no non-essential personnel in area. If H2S is
present, normal H2S operating procedures are to be followed, i.e.
breathing apparatus, buddy system etc. Personnel work duration
will not generally exceed 18hrs.
14.6.6. Sample Storage
Work Scope Storage and shipping of high pressure oil or gas samples.
Storage Area Must always be away from heat sources and sources of ignition.
Must be well ventilated.
Comments Samples must be in two phases for storage and shipment, i.e.
samples will have a gas cap. Samples must be labelled as being
flammable high pressure oil or gas samples.

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15. WIRELINE OPERATIONS
Although sometimes operationally necessary, wireline operations, both slickline or electric
wireline, carry an inherent risk which is even greater on an offshore exploration well test due
to the configuration of the test string and the well conditions. If possible, running wireline
through the test string and especially the annulus pressure operated tester valve should be
avoided. This must be avoided on deep, hot, high pressure wells.
Slickline tools are run for:
• Depth determination to check test string valves are fully open.
• Bottomhole sampling which can be taken above or below the test tools.
• Downhole pressure gauges, set in nipples or hung off.
• Fluid interface check to establish fluid levels, e.g. frac gel.
• Installing tubing plugs or downhole shut off tools which are set in nipples.
• Circulation devices, i.e. opening or closing sliding sleeves.
• Bailing to remove solids at a reverse circulating valve etc.
• Fishing for other slickline or electric wireline toolstrings.
Electric wireline tools are run for:
• Depth determination, i.e. to check TCP guns are on depth.
• Bottom hole sampling which can be taken above or below the test tools.
• Production logging, to establish zonal contributions to flow.
• Downhole pressure gauges which may be run with PLT tools.
• Perforating or re-perforating with Through-Tubing guns.
• Tubing punching to establish circulation.
• Tubing cutting to free a test string from a stuck packer, etc.
Both types of wireline require the use of long bails, or a C/T (coiled tubing) lifting frame, to
cater for the rigging up of the wireline BOPs and the lubricator on top of the flowhead.
Pressure testing is to be carried out against the lubricator valve. The main difference between
a slickline and electric line rig up is that double BOPs and a grease flowtube must be used to
achieve a seal on a braided cable.

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16. HYDRATE PREVENTION
Hydrates are complexes formed spontaneously by the combination of hydrocarbon gas
mixtures with free water under certain conditions of temperature and pressure. Physically
they are ice-like solids which can completely plug downhole tubing and/or surface lines.
Hydrates can form under both flowing or static conditions. The first indication of hydrates
forming in the tubing is a drop in flowing wellhead pressure, followed by an initially slow but
accelerating drop in wellhead flowing temperature.
The formation of hydrates can be predicted and key to prevention is understanding the
conditions under which they will form. These conditions are certain ranges of pressure and
temperature, with free water present. Under flowing conditions the expansion downstream of
a choke or other restrictions give a favourable regime for their formation. Under conditions of
no flow they can form as a kind of snow on the walls of tubing.
A downhole hydrate plug is potentially dangerous and should be avoided at all costs. The area
of most risks is in the string from the seabed upwards where the lowest temperature usually
occur.
It is of great importance to check the wellhead temperatures at frequent intervals and
immediately when the gas rate or flowing pressures are observed to decrease unexpectedly.
Hydrate prevention is based on the injection of triethylene glycol and/or methanol.
To prevent hydrate formation during the flow testing of high GOR (Gas/Oil Ratio) wells, pump
facilities shall be connected up to the following points:
• Sub Sea Test Tree
• Flowhead
• Data header
• Gas line downstream of the separator.
To prevent hydrate formations during shut-in periods, glycol should be injected continuously
into the vertical run of the flowhead as well as at the Sub Sea Test Tree.

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17. NITROGEN OPERATIONS
The main use of nitrogen on an exploration well test is to introduce a partial nitrogen cushion
into the test string by displacing the tubing contents through a tubing-annulus differential
pressure-operated circulation valve into the annulus. Fluid returns must be monitored to
ensure no nitrogen is allowed into the annulus.
The nitrogen cushion pressure can be rapidly reduced to give a very large drawdown when
perforating underbalance or bringing on a well which had already been perforated
overbalance. This would be useful on tight or depleted reservoirs. It could also be used for
detonating TCP guns using a hydro-mechanical firing device operating at a given tubing-
annulus differential by holding the annulus pressure and bleeding away the nitrogen cushion
pressure.
Alternatively, with the well open, the nitrogen could be bled off very slowly to minimise the
drawdown, for instance, on a poorly consolidated sand. The disadvantage with this is that it is
uncertain what is occurring downhole as the nitrogen is bled off. However the advantage is if
the well does not flow to surface, the tubing contents can be reverse circulated out of the well
to determine the what the influx was and, if needed, a second nitrogen cushion could be
circulated into placed in another attempt to bring the well in. If this failed, the well would have
to be gas lifted using a coiled tubing unit.

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18. OFFSHORE COILED TUBING OPERATIONS
Equipment for a coil tubing operation offshore for use on a well test is the same as on a
platform except that a lifting frame is installed to simplify the rig up. This must be rigged up on
the flowhead from the beginning as part of the landing string as this cannot be accomplished
afterwards.
The built-in lifting hoist must be a chain pulley type, which stops immediately the drive control
is released. It can also be used for the wireline rig-up making it easier and safer.
Coiled tubing on a well test is normally used for:
• Gas lifting using nitrogen
• Spotting fluids i.e. accurately placing fluids for squeezing, perforating etc.
• Logging (Stiff Wireline) in high deviations with cable inside the tubing.
The main limitation of coiled tubing is that it has a low burst and collapse pressure rating,
therefore a pre-job computer analysis should be run using all the expected well parameters
such as the expected well pressures and temperatures, internal pressures on the tubing, hole
angles, depths and tubing data etc.
When coiled tubing is to be run on a well test, it is essential that the sub-sea test tree is
dressed to be capable of cutting, whatever the size of the tubing.

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19. WELL KILLING ABANDONMENT
There are a number of methods for conducting a well kill operation in a well test situation,
dependent upon the well hardware and configuration, taking into account of any well problems
which have arisen. However, the two main methods under normal circumstances are;
‘Reverse Circulation’ and ‘Bullheading’.
Note: Bullheading from surface should never be carried out as a routine kill
method without prior permission from Eni-Agip management. Procedures
for any such method of well kill would be issued in the test programme.
Killing by reverse circulation is the preferred method of killing a well as it reduces the quantity
of foreign materials coming into contact with and prevents over pressuring the formation.
Bullheading is sometimes preferred in cases where the circulation method may not be
efficient due to gas entrainment etc.
Other methods of well kill are used in circumstances where there has been a circulating valve
failure or a blockage in the tubing. These are; ‘Bleed off and Bullhead’, ‘Reverse Circulate and
Bullhead’ and ‘Lubricate’. These are so specialised in nature that it is not practical for them to
be used without first thoroughly examining the well situation and then producing a detailed well
specific programme and are, therefore, not addressed in this manual.
On tests with Semi-Submersibles there is a well kill procedure for making the well safe for a
disconnection due to bad weather etc.
19.1. ROUTINE CIRCULATION WELL KILL
The normal procedure for killing a well is the forward circulation method which displaces the
formation fluids from the test string with kill weight fluid. This method can also be used in the
event of premature termination of an offshore test due to weather or any other reason when
there is sufficient warning and time allows. This procedure requires DST tool operation to
open the circulating device and control of the circulating pressure using the well test choke
manifold.
19.1.1. Circulation Well Kill Procedure
The following procedure is the normal method of well kill following the termination of a test
programme (Refer to figure 19.a).
1) After the final build up, or flow period, close the tester valve and pull any surface read
out tools out of the hole if being used.
2) Open the multi-function circulating valve and reverse out string contents, collecting
samples if required. Circulate to condition and balance tubing and annulus. Close the
circulating valve.
3) Pressure up on the annulus to open the tester valve. Pressure up on kill wing valve with
brine to slightly less than shut in well head pressure then open the kill wing valve. The
production wing valve should be closed.
4) Pressure up on the test string with brine, checking the pump volume.

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5) Calculate the maximum the bottomhole pressure to be applied, which must be kept
below the formation frac pressure.
6) If the formation takes the pumped fluid, continue bullheading down the test string and
liner below the packer to the bottom perforations. Check the volume of pumped brine.
7) A variation in the pumping pressure should be detected when brine reaches the
formation. Record the leak-off rate.
8) Carry out a 30min flow check. If static, proceed to step 14.
9) If the well takes brine at more than 5bbl/hr, the displacement of a temporary plugging pill
to bottom may have to be considered.
10) If the formation doesn’t take the pumped fluid or the injection rate is less than 0.1bpm
over a 3hrs period, close the kill side wing valve and tester valve.
11) With the multi-function circulating valve in the test position, open the single shot
reversing valve and reverse circulate until the tubing and annulus are in balance.
12) For tests using permanent packers, pull out seal assembly and reverse circulate at
least twice bottoms up, or until minimum gas returns.
For conventional DST, unseat the packer and bullhead the hole contents below the
packer into the formation. Reverse circulate again, if necessary, until tubing and
annulus are in balance.
13) Flow check the well.
14) Once the well is stable, pull string out of hole while carefully monitoring the hole volume,
especially while DST tools are in 7ins liner as the swabbing effect is to be avoided.
15) If the brine lost into formation is more than 5bbl/hr, the displacement of a temporary
plugging pill to bottom must be considered.
This may be composed of CaCO3, HEC or MICA etc. and the material must be
available on the rig to make up the appropriate weighted pill.

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19.2. BULLHEAD WELL KILL
Bullheading is only allowed by permission of Eni-Agip management.
If a well has good permeability, the simplest method of well kill is to bullhead from surface.
Bullheading is most effective when:
• The tubing contents are displaced without fracturing the formation
• Mixing between the hydrocarbons and the kill fluid will be limited, e.g. with a small
diameter tubing and in a vertical well.
The drawback of bullheading is when the formation may be fractured, as with low permeability
reservoirs. This can lead to a protracted well kill with hydrocarbons leaking back from the
fracture into the well bore and migrating upwards in the well.
As a very rough way of estimating if bullheading will fracture the formation is as follows:
a) Estimate the productivity index (PI) of the well form surface pressure and flow rate data.
b) Use the estimated of PI to calculate the injection pressure at a rate of 1bbl/min
(1,440bbl/d).
c) Compare the estimated injection pressure with the prognosed formation fracture
pressure.
19.2.1. Bullhead Kill procedure
The Bullhead kill procedure is:
1) Calculated the volume to the perforations.
2) Line up the cement pump with sufficient quantity of kill fluid.
3) Pressure up with the pump to equalise across the wing valve and open the valve.
4) At as fast a rate as possible, keeping below frac pressure, pump kill fluid.
5) Monitor when the fluid first reaches the formation by observing a pump pressure rise.
Once kill fluid reaches over the whole perforated interval it will be more difficult to
squeeze away fluids and the pressure will increase.
6) Continue to pump until the hole volume calculated is pumped plus a few barrels excess
to push away the kill fluid/well fluid interface.
7) Establish the circulation path, then unseat the packer (when a lock open tester valve is
run, unseating the packer will establish the circulation path).
8) Circulate bottoms up. If the well is taking losses, an LCM pill should be circulated in and
bullheaded against the formation.
9) Only when the well is safe may the string be pulled.

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19.3. TEMPORARY WELL KILL FOR DISCONNECTION ON SEMI SUBMERSIBLES
This operation does not involve pulling the string out of hole and killing the well is limited only
to filling up the string down to the tester valve, time allowing:
• Close the tester and kill the well by reverse circulation through the multi-function
circulating valve and continue with operations to disconnect.
If in an emergency situation, when there is insufficient time to kill the well, disconnection will
be implemented without the well kill. In this eventuality, there will still be the requisite number
of barriers on the well for safety, although reconnection to a live well has it’s own particular
risks. This operation would be detailed in a separate programme.
Figure 19.A- Reverse Circulate Decision Tree

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
19.4. PLUG AND ABANDONMENT/SUSPENSION PROCEDURES
Whenever feasible, a decision should be made on the disposition of the well as early as
possible, before any plugging operations are begun, whether or not the well is to be
suspended for future production purposes. Well plugging procedures and equipment will differ
depending upon the need for future well intervention. In particular, the choice of bridge plugs
used for abandonment of test intervals will be affected, especially if perforating guns have
been dropped into the sump below the plugs.
If the well is to be suspended, the course of action should be to install plugs which meet
regulations but can protect the formation from any further damage during re-entry. For
instance retrievable bridge plugs or packers can be used with a course of sand or saturated
salt between the plug and the cement plug. This allows the cement to be drilled up with both
the cuttings and sand being circulated out and the well displaced to clean brine before the
plug is pulled.
Often the ideal method of suspension is to use a permanent packer for the test which is also
used as the completion packer. This allows the packer to be plugged by wireline, with oil or
gas below, at the end of the test preventing any contamination of the formation.
Detailed plug and abandonment procedures will be issued by the Drilling and Completion
Department who are responsible for this part of the operation.
Note: If it is necessary, submit details of the methods and arrangements to be
used to the proper authorities to obtain their written approval prior to
commencement of work.
19.5. PLUG AND ABANDONMENT GENERAL PROCEDURES
1) Rig up wireline and run in the hole with gauge ring and junk basket to 10ft above the top
perforation/permanent packer. Pull out of the hole.
2) Run in the hole and set a bridge plug 10ft above top perforation/ permanent packer. Test
the bridge plug to 500psi above leak off pressure.
3) Run in the hole and set a second bridge plug immediately above the first. Test this
bridge plug to 500psi above the leak off pressure.
Note: Use of two bridge plugs instead of bridge plug and cement is to avoid
contamination of the completion brine.
Separate detailed procedures will be issued as part of the well specific drilling programme.
Pre-drilled development wells will also be covered by well specific drilling programmes.

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
20. HANDLING OF HEAVYWATER BRINE
Both CaBr2/CaCl2, as brine and powder can cause skin irritation and even blistering if allowed
to remain in contact with the skin. It is therefore important that personnel involved in work
where they may be exposed to the brine or powder should be protected as follow:
a) Rubber gloves (gauntlet type to cover wrists)
b) Waterproof slicker suits with hoods
c) Rubber boots (leather boots are shrivelled by the brine)
d) Full face masks for use when mixing powdered CaBr2/CaCl2.
e) Barrier cream (e.g. ‘Vaseline’) for use on exposed skin, particularly face, neck and
wrists, to prevent direct skin contact with the brine.
Additionally, whenever powder/brine is inadvertently splashed onto clothing, then the affected
clothes should be changed and washed forthwith. Never allow brine to dry on the skin or
clothes.
If brine is splashed into the eyes, wash the eyes at once with copious amounts of fresh water.

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Appendix A - Report Forms
A.1. Daily Report (ARPO 02)
WELL NAME
FIELD NAME
District/Affiliate Company
DATE: ARPO 02 Cost center
Rig Name RT Elevation [m] Well Code
Type of Rig Ground Lelel / Water Depth [m] Report N° of
Contractor RT - 1st flange / Top Housing [m] Permit / Concession N°
Well Last casing Next Casing BOP Type Ø w.p. [psi] M.D. (24:00) [m]
Ø nom.[in] Stack T.V.D. (24:00) [m]
Top [m] Diverter Total Drilled [m]
Bottom [m] Annular Rotating Hrs [hh:mm]
Top of Cmt [m] Annular R.O.P. [m / h]
Last Survey [°] at m Upper Rams Progressive Rot. hrs [hh:mm]
LOT - IFT [kg/l] at m Middle Rams Back reaming Hrs [hh:mm]
Reduce Pump Strockes Pressure Middle Rams Personnel Injured
Pump N° 1 2 3 Middle Rams Agip Agip
Liner [in] Lower Rams Rig Rig
Strokes Last Test Others Other
Press. [psi] Total Total
Lithology
Shows
From (hr) To (hr) Op. Code OPERATION DESCRIPTION
Operation at 07:00
Mud type Bit N° Run N° N° Run N° Bottom Hole Assembly N° __________ Rot. hours
Density [kg/l] Data Description Ø Part. L Progr.L Partial Progr.
Viscosity [s/l] Manuf.
P.V. [cP] Type
Y.P. [g/100cm2
] Serial No.
Gel 10"/10' / IADC
Water Loss [cc/30"] Diam.
HP/HT [cc/30"] Nozzle/TFA
Press. [kg/cm2
] From [m]
Temp. [°C] To [m]
Cl- [g/l] Drilled [m]
Salt [g/l] Rot. Hrs.
pH/ES R.P.M.
MBT [kg/m3] W.O.B.[t]
Solid [%] Flow Rate Stock Quantity UM Supply vessel
Oil/water Ratio. Pressure
Sand [%] Ann. vel.
pm/pom Jet vel.
pf HHP Bit
mf HSI Total Cost Supervisor:
Daily Losses [m3
] I O D L I O D L Daily
Progr. Losses [m3] B G O R B G O R Progr.
DAILY REPORT
Drilling

ARPO
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Agip Division
REVISION
STAP-P-1-M-7130 0
A.2. Waste Report (ARPO 6)
WELL NAME
FIELD NAME
DATE: ARPO-06 Cost center
Report N° Depth (m) Mud TypeFrom [m] Interval Drilled (m) Density (kg/l)
To [m] Drilled Volume [m
3
] Cl- concentration (g/l )
Phase size [in] Cumulative volume [m
3
]
Water consumption Phase /Period [m
3
] Cumulative [m
3
]
Usage Fresh water Recycled Total Fresh water Recycled Total
Mixing Mud
Others
Total
Readings / Truck Fresh water [m
3
] Recycled [m
3
]
Mud Volume [m
3
] Phase Cumulative Service Company Contract N°
Mixed Mud Company
Lost Waste Disposal
Dumped Transportation
Transported IN
Transported OUT
Waste Disposal Period Cumulative Remarks
Water base cuttings [t]
Oil base cuttings [t]
Dried Water base cuttings [t]
Dried oil base cuttings [t]
Water base mud [t]
Oil base mud transported IN [t]
Oil base mud transported OUT [t]
Drill potable water [t]
Dehidrated water base mud [t]
Dehidrated oil base mud [t]
Sewage water [t]
Transported Brine [t]
Remarks
Supervisor
Superintendent
WASTE DISPOSAL
Management Report

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
A.3. Well Problem Report (ARPO 13)
FIELD NAME
WELL NAME
DATE: ARPO -13 Cost center
Problem Top [m] Start date
Code Bottom [m] End date
Well Ø Measured Depth Vertical Depth KOP [m] Mud in hole
Situation Top [m] Bottom [m] Top [m] Bottom [m] Max inclination [°] Type
Open hole @ m Dens.[kg/l]:
Last casing DROP OFF [m]
Well problem Description
Solutions Applied: Results Obtained:
Supervisor Supervisor Supervisor
Remarks at District level:
Superintendent
Lost Time hh:mm Loss value [in currency]
Remarks at HQ level Pag.
Of
WELL PROBLEM
REPORT

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
A.4. Malfunction & Failure Report(FB-1)
MALFUNCTION & FAILURE REPORT
(FEED BACK REPORT 01)
Report Date:
Well Name: Well Code:
General Information
Contract No: Contract Type: Contractor:
Service/Supply:
Drilling Completio
n
Workover Duration Dates of Failure: Distributed By:
RIG SITE
Description of Failure:
Drilling & Completions Company Man:
Adopted or Suggested Solution(s):
Contractor Contingency Measures:
Contractor Representative:
DISTRICT OR SUBSIDIARY NOTES:
Failure Classification Status Operations Manager:
Technical Normal
Management/Organisation Extreme Time Lost:
Safety/Quality Innovative
Adverse Estimated Cost of Failure:
MILAN HEAD OFFICE NOTES:
Analysis Code:
District/Subsidiary

ARPO
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Agip Division
REVISION
STAP-P-1-M-7130 0
A.5. Contractor Evaluation (FB-2)
CONTRACTOR EVALUATION
(FEED BACK REPORT 02)
Report Date:
Well Name: Well Code:
General Information
Contract No.: Contract Type: Contractor:
Service/Supply: Distributed By:
R1 Technical Requirements
FB_01 REPORT REFERENCES
FB Report No.: Time Lost (Hr.Min): Economic Cost (£M):
Category Evaluation Score (0-9)
Suitability of Equipment and Materials
Compliance of Equipment and Materials to the
Adequacy of Personnel
Meeting with Operational Programme Requirements
Meeting with Contract Operation Timings
Equipment Condition/Maintenance
R2 Management and Organisational Requirements
Availability of Equipment and Materials
Technical and Operational Support to Operations
Capability and Promptness to Operational Requests
R3 Safety and Quality Assurance Requirements
Meeting with the Contract Agreement DSS
Availability and Validity of Requested Certificates
Meeting with Contract Quality Assurance Terms
Event Support Documentation
Type of
Document:
Subject: Issued By: Date:
Notes:
Failure Status Operations Manager Drilling & Completions Manager
Normal Extreme Adverse Innovative
District/Subsidiary

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Appendix B - ABBREVIATIONS
AC/DC Alternate Current, Direct Current
API American Petroleum Institute
BG Background gas
BHA Bottom Hole Assembly
BHP Bottom Hole Pressure
BHT Bottom Hole temperature
BMT Blue Methylene Test
BOP Blow Out Preventer
BPD Barrel Per Day
BPM Barrels Per Minute
BPV Back Pressure Valve
BSW Base Sediment and Water
BUR Build Up Rate
C/L Control Line
CBL Cement Bond Log
CCL Casing Collar Locator
CDP Common Depth Point
CET Cement Evaluation Tool
CGR Condensate Gas Ratio
CR Cement Retainer
CRA Corrosion Resistant Alloy
C/T Coiled Tubing
DC Drill Collar
DE Diatomaceous Earth
DHM Down Hole Motor
DHSV Down Hole Safety Valve
D&CM Drilling & Completion Manager
DP Drill Pipe
DPHOT Drill Pipe Hang off Tool
DST Drill Stem Test
E/L Electric Line
ECD Equivalent Circulation Density
ECP External Casing Packer
EMS Electronic Multi Shot
EMW Equivalent Mud Weight
EP External Pressure
ESD Electric Shut-Down System
ESP Electrical Submersible Pump
ETA Expected Arrival Time
FBHP Flowing Bottom Hole Pressure
FBHT Flowing Bottom Hole Temperature
FPI/BO Free Point Indicator / Back Off
FTHP Flowing Tubing Head Pressure
FTHT Flowing Tubing Head Temperature
GLR Gas Liquid Ratio

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REVISION
STAP-P-1-M-7130 0
GOC Gas Oil Contact
GOR Gas Oil Ratio
GP Gravel Pack
GPM Gallon (US) per Minute
GPS Global Positioning System
GR Gamma Ray
HAZOP Hazard and Operability
HHP Hydraulic Horsepower
HO Hole Opener
HP/HT High Pressure - High Temperature
HW/HWDP Heavy Weight Drill Pipe
IADC International Association of Drilling Contractors
IBOP Inside Blow Out Preventer
ID Inside Diameter
IPR Inflow Performance Relationship
JAM Joint Make-up Torque Analyser
L/D Lay Down
LAT Lowest Astronomical Tide
LC 50 Lethal Concentration 50%
LCDT Last Crystal to Dissolve o
C
LCM Lost Circulation Materials
LEL Lower Explosive Limit
LN Landing Nipple
LOT Leak Off Test
LQC Log Quality Control
LTA Lost Time Accident
M/D Martin Decker
M/U Make Up
MAASP Max Allowable Annular Surface Pressure
MD Measured Depth
MLH Mudline Hanger
MLS Mudline Suspension
MMS Magnetic Multi Shot
MODU Mobile Offshore Drilling Unit
MPI Magnetic Particle Inspection
MSCL Modular Single Completion Land
MSL Mean Sea Level
MUT Make up Torque
MW Mud Weight
MWD Measurement While Drilling
NACE National Association of Corrosion Engineers
NDT Non Destructive Test
NSG North Seeking Gyro
NTU Nephelometric Turbidity Unit
OBM Oil Base Mud
OD Outside Diameter
OH Open Hole

ARPO
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Agip Division
REVISION
STAP-P-1-M-7130 0
OIM Offshore Installation Manager
OMW Original Mud weight
OWC Oil Water Contact
P&A Plugged & Abandoned
P/U Pick up
PBR Polished Bore Receptacle
PDM Positive Displacement Motor
PI Productivity Index
PLT Production Logging Tool
POB Personnel On Board
POOH Pull Out Of Hole
PPB Pounds per Barrel
PPG Pounds per Gallon
ppm Part Per Million
PVT Pressure Volume Temperature
Q Flow Rate
Q/A Q/C Quality Assurance, Quality Control
R/D Rig down
R/U Rig up
RBP Retrievable Bridge Plug
RCP Reverse Circulating Position
RFT Repeat Formation Test
RIH Run In Hole
RKB Rotary Kelly Bushing
ROV Remote Operated Vehicle
RPM Revolutions Per Minute
RT Rotary Table
S/N Serial Number
SBHP Static Bottom Hole Pressure
SBHT Static Bottom Hole Temperature
SCC Stress Corrosion Cracking
SDE Senior Drilling Engineer
SF Safety Factor
SG Specific Gravity
SICP Shut-in Casing Pressure
SPM Stroke per Minute
SR Separation Ratio
SRG Surface Readout Gyro
SSC Sulphide Stress Cracking
TCP Tubing Conveyed Perforations
TD Total Depth
TG Trip Gas
TGB Temporary Guide Base
TOC Top of Cement
TOL Top of Liner
TVD True Vertical Depth
UR Under Reamer

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REVISION
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VBR Variable Bore Rams (BOP)
VDL Variable Density Log
VSP Velocity Seismic Profile
W/L Wire Line
WBM Water Base Mud
WC Water Cut
WL Water Loss
WOC Wait On Cement
WOW Wait On Weather
WP Working Pressure
YP Yield Point

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Appendix C - BIBLIOGRAPHY
Document: STAP Number
Other
API Specification No 811-05CT5

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