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
REVISION
STAP-P-1-M-7130 0
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

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

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

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

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

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

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

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

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

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

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

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

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
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,

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

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

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

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

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

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 5.A- SSTT Arrangement

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

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

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

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
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).

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 6.A- Typical Jack Up/Land Test String - Packer With TCP Guns On Packer

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 6.B - Typical Test String - Production Packer With TCP Guns Stabbed Through

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 6.C - Typical Jack Up/Land Test String - Retrievable Packer

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 6.D - Typical Semi-Submersible Test String - Retrievable Packer

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

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

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

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

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

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

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

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

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

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
Figure 7.A- Surface Equipment Layout
7.2. EMERGENCY SHUT DOWN SYSTEM

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

ARPO
ENI S.p.A.
Agip Division
REVISION
STAP-P-1-M-7130 0
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:

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

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

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

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

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

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

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

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

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

Well test-procedures-manual

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to Well test-procedures-manual

Similar to Well test-procedures-manual (20)

More from Narendra Kumar Dewangan

More from Narendra Kumar Dewangan (12)

Well test-procedures-manual