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7/15/2019 129842114 Well Completion Design Guideli[1]
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1. PREFACE
GUIDELINES FOR WELL COMPLETION DESIGN
CONTENTS
2. INTRODUCTION
3. ORGANISATIONANDRESPONSIBILITIES
3.1 Technical role - Responsibilities
3.2 Operational role - Responsibilities
4. WELLCOMPLETIONDESIGN
Role of the completions engineer
Developing a design philosophy
Defining well barriers
Defining materials and sealing requirements
Materials
4.1.1.1Cast iron
4.1.1.2 Carbon steel
4.1.1.3 Low alloy steels
4.1.1.4 Corrosion resistant alloys (CRA)
4.4.2 Sealing systems
4.4.2.1 O-rings
4.4.2.2T-seal (GT ring)
4.4.2.3 Chevron V-packing and bonded seals
4.4.2.4Packer elements
4.1
4.2
4.3
4.4
4.4.1
4.5 Types of completions
4.5.1 Open Hole
4.5.2 Slotted Liner
Date 1/3/98 IPrep. by : IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 1
Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1This document contains CONF IDENT IAL and PROPRIETARY INFORMAT ION o f P remie r O il PLC. This d oc ument and t he inf onnat ion disclosed within shall not be reproduced in whole or Inpart to any thi rd par ty anypurpose whatsoever including conceptual design, engineering I manufacturing or oonstruction without the express written permi ss ion o f Premier 011PLC .
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5. RESERVOIRANDWELL PERFORMANCE
5.1 Basic principles of well deliverability
5.1.1 Inflow Performance Relationship
5.1.2 Vertical Lift Performance
5.1.3 Developing a well performance model
6. SYSTEMDESIGN
6.1 Tubing design
6.1.1 Hydraulic performance
6.1.2 Mechanical loading
6.1.3 Material selection
6.2 Flow controls and isolation equipment
6.2.1 Safety valves
6.2.2 Packers
6.2.3 Nipples, plugs and accessories
6.3 Special equipment and requirements
6.3.1 Polished bore receptacles
6.3.2 Formation isolation valves
7. COMPLETIONDESIGNFORSPECIALAPPLICATIONS
7.1 Wells requiring artificial lift
7.1.1 Electrical Submersible Pump completions
7.1.2 Gas lift completions
7.1.3 Coiled Tubing completions
7.2 Completion design in wells with sanding problems
7.2.1 Sand production prediction
7.2.2 Gravel packed completions
Date 1/3198 IPrep. by: IESL I Guidelines to Well Completion Design I Section No. IPage No.: 2
Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1
This document contai ns CONFIDE NTIA L and P ROP RIETARY INFORMATION of P rem ier Oi l PLC. This do cum ent and the information disclosed within shall not be reproduced in whole or Inpar t to any thi rd par ty any
purpose whatsoever inducling c on ce pt ua l d es ig n, e ng in ee ri ng , m an uf ac tu ri ng o r c on st ru ct io n without t he e xp re ss w ri ne n pennission of Premi er Oi l PLC.
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7.2.3 Slotted liners and screens
7.2.4 Selective perforations
8. OPERATIONALASPECTS OF WELLCOMPLETIONS
8.1 Installing and retrieving the completion string
8.1.1 Equipment preparation
8.1.2 Component testing
8.2 Wireline operations
8.2.1 Equipment
8.2.2 Type of operations
8.2.3 General operational procedures
8.3 Coiled Tubing operations
8.3.1 Equipment
8.3.2 Type of operations
8.3.3 General operational procedures
APPENDICES
Appendix 1
Appendix 2
Appendix 3
Date 1/3/98 IPrep.by: IESL I Guidel ines to Well Completion Design ISection No. IPage No.: 3
Ref. I I RDS Resource - Premier Oil Pic I Re vis io n: A IVersion: 1
This document contains CONFIDENTIAL and PROPRIE TA RY INFORMA TI ON of Premi er Oil P LC, Thi s document and the Information disclosed within shall not be reproduced in whole or In p art to any thi rd par ty anypurpose whatsoever indueling c onceptual des ign. engineering, manufactur ing or const ruct ion without the express wriUenpermission of Premier Oil PLC.
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PREMIER OIL
GUIDELINES FOR COMPLETIONS DESIGN
1. PREFACE
This manual establishes guidelines for Premier Oil engineers who are designing
completions that are to be installed in company onshore, offshore or subsea oil
and gas wells.
Completions design varies significantly according to factors such as geographical
location (Cuba, Pakistan, UKCS, etc.), local regulations and equipment availability.
The objective of this manual is to provide the completions engineer with detailed
information about equipment, operational factors and well safety considerations, so
that the completion design can be ??????? out according to Premier guidelines,
approved industry practices andwell requirement regulations.
Accordingly, information is presented about a wide range of completion
alternatives and also equipment options with details of their operating principles.
However, the manual is not intended to define precise parameters on which to
base any particular completion design.
Date 1/3/98 IPrep.by : IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 4-1Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1
Thi s do cument c ont ain s CONF IDENT IAL an d PROPRIETARY INFORMATION of Premier Oil PLC. This document and the information disclosed within shall not be reproduced in whole or in part to any third par ty any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without t he e xpr es s wr it ten p ermi ssi on of Pr emi er O il P lC.
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4. WELLCOMPLETIONS DESIGN
Important primary factors in designing a well completion are developing a
completion philosophy, specifying the well safety barriers and operating conditions
and defining the roles and responsibilities of involved personnel.
The very first step in the design must be to develop a suitable completion
philosophy. This must be closely followed by defining a suitable system of well
barriers as a foundation for the detailed design process. However, there are no
formal regulations specifying the numbers and types of barrier equipment that
should be used in particular conditions, so the completions engineer must rely on
experience to select those barriers that will meet the project requirements. As
designing a successful well completion is dependent on choosing suitable
equipment metallurgy and appropriate sealing systems, these are
comprehensively reviewed in Section 4.4, with supplementary metallurgical
information in Section 6.
4.1 Role of the completions engineer
Designing a well completion requires information from various other disciplines
such as drilling engineering, reservoir engineering and Geosciences. The
completions engineer integrates the input from each source so that the optimum
completion can be achieved. The design process is a team effort that addresses
conflicting individual concerns and reaches a mutually acceptable compromise. A
typical area of conflict is the choice of drilling fluid - the one giving the best drilling
ROP for the reservoir conditions might cause major formation damage and hence
a serious reduction in productivity. In this situation, a balance must be struck that
best meets the conflicting requirements.
Ideally, a completions engineer would both design the system and participate in
its installation. As this is not always possible, the responsibility for operations may
be assigned to a suitably experienced completions supervisor who would report to
Date 1/3/98 IPrep.by : IESL I Guidelines to Well Completion Design ISectionNo. IPageNo.: 8
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This doc ument co nt ai ns CONF IDENT IAL and PROPRIETARY INFORMATION of P remie r O il P LC. This d oc ument and the information disclosed within shall not be reproduced in whole or in part to any thi rd par ty any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wri tten permiss ion of Premier Oil PLC.
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the completions engineer. In this event it is essential that the technical engineer
and operations supervisor develop a close working relationship to ensure that all
the objectives of the project are met. The main responsibilities of the two roles are:
Technical responsibilities
. Develop the overall design philosophy
. Carry out well performance calculations and sizing of tubing
. Determine mechanical and thermal loads for different operating conditions
. Select methodologies, specific equipment and components
. Design and/or supervise the selection of any required artificial lift option
. Develop and/or supervise the selection of an optimum perforating strategy
. Review the overall well control and safety requirements
. Contribute to the preparation of ITT's and evaluation of tender documents
. Prepare equipment and services costs for the completion operations
. Prepare final well completion report
Operational Responsibilities
. Organise the logistics and installation operations for the completion
. Supervise the preparation and testing of sub-assemblies
. Contribute to preparation of the installation program
. Contribute to preparation and organisation of the well testing program
. Supervise wireline operations during installation of the completion
. Supervise installation of the completion
. Ensure implementation of all safety procedures and policies
. Prepare operational reports
Any Completions Supervisor who may be given responsibility for the
installation operations reports to the Completions Engineer.
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 9
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This do cument c ont ai ns CONF IDENT IAL an d PROPR IETARY INFORMATION of Pr em ie r Oil PLC. This document and the information disclosed within shall not be reproduced in whole or in part to any third part y any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wr it ten p ermi ssi on of Pr emi er O il P LC .
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4.2 Developing a design philosophy
A well completion is an integrated set of equipment and components, that has
been specifically designed to produce hydrocarbons from a particular reservoir as
cost-effectively and safely as possible. As designing a completion demands
engineering expertise beyond the capability of a single individual, it must be carried
out by a team that normally is led by the completions engineer. Various disciplines
contribute to the design process and their input, as well as that of management,
will have a significant impact on the final solution. However, in most cases the ideal
solution is not the most practical. so compromises are necessary.
The most realistic compromise for a particularset of conditions willlead to a
well-engineered solution.
A clear completion philosophy must be defined at a very early stage in the
project. As a main objective, the completion should be the simplest possible, in
order to:
. Maximise productivity
. Minimise initial CAPEX
. Minimise workover and intervention requirements
. Minimise risk and safety exposure
. Maximise recovery by making provision for future operations
In certain situations some of these factors can be mutually exclusive, so that
careful engineering is necessary to achieve an "optimum solution" compromise.
Defining well barriers
One of the most important tasks in present day completion design is to
understand and identify the well safety requirements. Formation and other
pressurised fluids must be contained within the wellbore to prevent their
Date 1/3/98 IPrep. by : IESL I Guidel ines to Well Completion Design ISectionNo. IPage No.: 10
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
This document contains CONF IDENT IAL and PROPRIETARY INFORMAT ION o f P remie r O il PLC. This d oc ument and t he i nf onn at io n disclosed within shall not be r ep roduced i n who le o r i npar t to any thi rd par ty any
purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express wrinen penniss ion of Premier Oil PlC.
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uncontrolled release and consequential serious risk to life, property and the
environment. Such containment is usually mechanical and is provided by the
installation of appropriate well safety barriers.
The national or local regulations for an operating area and also company policy
may dictate the number, type and placement of well safety barriers. As there can
be radical differences in regulations between different countries in the same
geographical area, it is essential that the well barrier requirements are addressed
in the very earliest stages of the design process. Barriers commonly used in
production and for well intervention operations are tabulated below.
WELL BARRIERS SUMMARY TABLE
I New models can be used
COMPONENT I LOCATION POSITION CCEPTABLE COMMENTS
BARRIER
Wireline plugs Subsurface Tubing Yes Set in nipples
Tubing Yes Set in tubing only
Tubing or wireline retrievableSafety valves Subsurface Tubing or annular Yes for either the tubing or annular
space
Injection valves Subsurface Tubing No Could be accepted in waterinjection wells.
Fluid column Subsurface Tubing or annular No Not on its own, only if usedwith the mechanical barriers
Packers Subsurface Tubing or annular Yes Permanent or retrievable
Formation isolation Subsurface Casing No Most current1 valves only holdvalves pressure from above
Burst disc Subsurface Tubing I Tail pipe Yes Has been used in the UK
DST strings Subsurface Tubing Yes Not to be used as a
permanent barrier
Tree valves Surface Tree Yes In some areas the whole tree
is considered a single barrier
Riser systems Surface Subsea only Yes Suitably rated
Wireline plug or BPV Surface Tubing hanger Yes Set on hanger profile
BOPs Surface Tree or riser section Yes For intervention operations
Strippers Surface Riser Yes Properly tested
Gate valves Surface Riser Yes Properly tested
Date 1/3/98 IPrep. by : IESL I Guidelines to Well Completion Design I Section No. I Page No.: 11
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This document contains CONFIDENTIAL and PROPRIE TA RY INFORMATION of Premi er Oil PLC. Thi s document an d the in form atio n disclosed within shall not be reproduced i n who le o r i npar t to any t hird pa rty any
pur pose wha ts oeve r Inc luding conceptual design. engineering, manufacturing or construction without t he exp ress wrinen pennisslon of Premi er Oil P LC.
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Illustrated below is the barrier status in a North Sea (UKCS) subsea multifunction
well with production through the tubing and injection down the annulus.
Barrier status example - Subsea well -UKCS
This example may appear to be unduly complex with hydrocarbon production up
the tubing and water injection down the annulus. However, with respect to barriers
this must be treated as twin wells where a situation in one can affect the other -
e.g. a tubing leak. The barrier system should be such that the remaining operation
can continue, avoiding total shut down of both production and injection.
There is no single solution to the problem of defining a well barrier system.
Ultimately, the completions engineer must develop realistic alternatives for review
with senior operating and technical personnel. Only with a mutually agreed barrier
system can there be technically sound, cost effective and, in particular, safe
operation of the well.
Fluid SCSSSV Surface I Deep set Shallow set Christmas
Column Downhole Injection Injection Tree
plug(s) valve valve valves
Initial . . . . .Completion
Production . .
Injection . .
Combined . . .ProdIlnj
Workover . . . . .
Tree . . . . .Removal
Date 1/3/98 IPrep. by : IESL I Guidelines to Well Completion Design I Section No. I Page No.: 12
Ref. I I RDS Resource - Premier Oil PIc IRevision: A IVersion: 1
This document contains CONFIDENTIAL and PROPRIETARY INFORMATION ofPremier Oil PLC. This document and the i"foonatlon disclosed within shall not be reproduced i n who le o r i n par t to any third party any
purpose whatsoever i"chlding conceptual design. engineering, manufacturing or constructionwithout the express written permission of Pr emi er Oi l P LC.
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4.4 Defining equipment materials and sealing systems
As a critical factor in completion design is the selection of correct equipment
materials and seal specifications, the completions engineer requires technical
support from a production chemist. The large variety of materials available makes
it essential to closely define the working environment. Of primary importance are
the reservoir temperature and pressure and the characteristics of its fluids -
especially the GOR and the C02, H2S and chloride content. The most common
materials and seal systems are reviewed later in this section, with guidelines for
their selection.
Also to be considered is the financial aspect of selecting a particular material and
the impact this will have on overall project costs. For water injection wells with
expected high corrosion rates, no decision on metallurgy should be made until a
full economic assessment of the projected well life has been made and the effect
on equipment costs calculated for each option.
4.4.1 Equipment materials and metallurgy
With the exploitation of ever deeper reservoirs, materials that are more resistant
are required to cope with the higher temperatures and increasingly complex fluids.
Low carbon steels that were originally developed for oilfield applications are no
longer adequate for these more demanding conditions. The need for completions
to be cost-effective has led to the development of multi-material components to
meet specific applications. Thus, inwells producing only moderate amounts of C02
components such as packer systems can have the "wetted" parts that are exposed
to production fluids, such as the mandrel made of 13% chrome steel, while
conventional carbon steel is used for the "unwetted" rest of the body and activating
mechanism. However, other applications like seawater injection require exotic
materials such as titanium or duplex steel. In such cases the completions engineer
must consider using these materials despite the cost implications. Classified below
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 13
Ref. I I RDS Resource - Premier Oil PIc I Revision: A I Version: 1
This document contains CONF IDENT IAL a nd PROPRIETARY INFORMATION of P remi er O il PLC. This do cument an d t he i nf ormat io n disclosed within shall not be reproduced in whole or in p ar t t o a ny t hi rd pa rt y any
purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written permission of Premier Oil PLC .
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with cost factor relative to carbon steel are the metals most commonly used in the
fabrication of completion equipment.
Metals commonlv used in the fabrication of comcletion eauicment
MATERIAL TYPE COST
RATIO
CAST IRON
Grey cast ironDuctile cast iron
White cast iron
CARBON
STEEL 1
Low carbon < 0.3 %
High carbon 0.3% < C < 1.0 % 1
LOWALLOY
STEELS
Low % of : Chromium
MolybdenumNickel
3
STAINLESS
STEEL
Semi-stainless steel
Martensitic
Austenitic/Ferric
Duplex
5
30
15
High % of : Chromium
MolybdenumNickel
XOTIC
ALLOYSTitanium
Brass & bronze
Eintered carbides
Composites
50
60
API grade. 2. Corrosion Resistant Alloys
4.4.1.1 Cast iron
Although it has low ductility and cannot be cold worked, cast iron is very resistant
to erosion and wear. Inexpensive and ideal for casting, it is easily milled and is
Date 1/3/98 IPrep. by : IESL -, Guidelines to Well Completion Design I Section No. IPage No.: 14
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This document conta ins CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. Thi s document and the infonnation disclosed w it hi n sha ll n ot b e r ep roduced i n who le o r i n p ar t t o an y t hi rd p ar ty any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written permission o f Pr emier O il PLC.
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used mainly in packers, bridge plugs and downhole pumps. There are three types
of cast iron whose mechanical properties differ according to the distribution of the
carbon content: grey cast iron is brittle and not NACE approved, it is used in
applications of up to 5000 psi. Ductile cast iron is less brittle than grey cast iron,
but has a higher strength, the white form is very brittle and difficult to machine
however, and it is very wear resistant. Both ductile cast iron and white cast iron are
commonly used in applications of up to 7500 psi.
4.4.1.2 Carbon Steel
With less than 1 % carbon content, carbon steels are softer and less corrosive
than with 2 %, but the whole range have low corrosion resistance. The NACE
approved low carbon type «0.3% C) is used for low strength tools. Though notheat treatable, the large grain size makes it resistant to C02. High carbon types
(0.3-1.0% C) can be heat treated and are used in perforating guns, K55, Nao and
DE drill pipe and AISI 1035 - 1045 materials.
4.4.1.3 Low alloy steels
Low alloy steels are the main types used in the manufacturing of completion
components, adding other metallic elements to the steel as alloys enhance themechanical properties. The most commonly added are:
. chromium (Cr) at -1 % increases corrosion resistance, hardness, wear
resistance and high temperature strength
. molybdenum (Mo) at - 0.2 % improves surface hardening and corrosion/wear
resistance
. Nickel (Ni) at -1.75 % improves strength and corrosion resistance.
4.4.1.4 Corrosion resistant alloys (CRA)
Stainless steels
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 15
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This document contains CONFIDENT IAL and PROPRIETARY INFORMATION of Premier Oil PLC. This documen t and the Informa tion disclosed within shall not be reproduced I n who le o r i n par t t o any t hi rd par ty any
purpose whatsoever Including oonceptual design. engineering, manufacturing or construction without the express written pe rmi ssion of Premie r Oi l PL C.
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Increasing the chromium content to as much as 12% greatly improves corrosion and
thermal resistance. The properties of a steel can be modified further by varying the
alloy content or by heat treatment.
Semi-stainless alloys. 4340 steel, 9% Cr + 1% Mo
· Suitable for H2Sstress corrosion cracking (SCC)
· Acceptable C02 resistance only below 150°F
· Only suitable for chloride corrosion below 150°F
· Not resistant to combined corrosion above 350°F
Martensitic · AISI410:-11.5-18% CR, 13% Cr
· Suitable for H2SSCC and chlorides SCC if treated
· Good C02 corrosion resistance «0.8 mpy at 150°F)
· Medium chloride (50K ppm) corrosion resistance < 300°F
· Medium combined corrosion resistance at 350°F (1 mpy)
Austenitic/Ferric · AISI 304, 316,440
. 17-4 pH
· Cr, Ni, Mn > 23%; 15-24% Cr; 8-22% Ni; 2% Mn
· Acceptable resistance for H2SSCC
· Susceptible to chlorides SCC above 150°F
· High C02 resistance
· Used mainly for low strength tool components requiring
good resistance to pitting or weight loss corrosion. Also
used in low temperature corrosive wells
Duplex . Cr 22%, 25%, 28%
. 32% Ni, 28% Cr (Sanicro 28%; Cabval VS 28, etc)
. Not suitable for H2S(unless has Ni content)
. High C02 corrosion resistance
. Not suitable for completion accessories in H2S
Date1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 16
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PlC. This document and the information disclosed withinshal l not be reproduced in whole or in par t t o an y t hir d party any
purpose whatsoever including conceptual design, engineering, manufacturing or constnJdton without t he e xp res s wr it ten permi ss ion of P remie r O il PLC .
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. Good chlorides resistance <300°F and <100K el. Rapid
corrosion at higher temperatures
. Used for tubes where high strength and good corrosion
resistance required
Exotic Alloys (high Chrome content)
Monel, Inconel
Incoloy
. Very high resistance to e02 corrosion up to 100 psia
partial pressures and at elevated temperatures
. Resistant to H2Ssee and chlorides see
. Resists chlorides corrosion at moderate temperatures
· Not combined corrosion resistant
. Often used for critical tools (SSV) and in pump valves for
severe environments
Super alloys for · Hastelloy - tubular goods
severe environments. Pyromet 31 - high strength items (SSSVs, tools, nipples)
· MP35N wireline
Brass and bronze · Too soft for most operations in oilwells
. Have good corrosion resistance but can cause galvanic
corrosion
. Occasionally used in valves of rod pumps for which they
are chrome plated
Sintered carbides · Uranium or titanium carbides
· Good corrosion resistance
· Used to make lightweight balls for rod pumps
General Corrosion Quidelines for tubinQ materials
Date 1/3/98 IPrep.by : IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 17
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
This document contains CONF IDENT IAL and PROPRIETARY INFORMAT ION of P rem ier O il PLC. Thi s do cument an d t he i nf orma tio n d is clo sed wi th in s ha ll n ot b e r ep ro du ce d i n w ho le or in part to any third party any
purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written permission of Premier Oil PLC.
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The tendency of a metal to corrode in the presence of a gas such as carbon
dioxide (C02) is primarily a function of the gas partial pressure and the
temperature, because water content has little influence on the process. One of the
most commonly used methods of calculating corrosion rates in tubulars was
developed byWaard and Milliams in the following equation:
LogR = 8.78 - (2320/ [T+ 273] ) - 5.55 X10-3 T + 0.67 Log PC02 Eq.
Where
R Corrosion rate in mil/year
T Temperature in degrees Celsius
PC02 Partial pressure of the carbon dioxide content inPSI
Material Yield Strength H2S cr CO2
[kg/mm2]
Carbon API Grade 50 Yes - No
Steel Well Grade 100 No - No
Stainless Steel - - -
Martensic 65 - No Yes
Duplex 50 Yes Yes Yes
Austenitic 35 Yes Yes Yes
NiAlloy 50 Yes Yes Yes
Date 1/3/98 IPrep.by : IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 18
Ref. I I RDS Resource - Premier Oil Pic 1 Revision : A IVersion: 1
Thi s d oc umen t c on tai ns CONF IDENTIAL an d PROPRIETARY INFORMAT ION of Pr emi er OilPLC. This document and the information disclosed within shall not be reproduced in whole o r in p ar t to any third party any
purpose whatsoever Indueling conceptual design, engineering, manufacturing or construction without the express written permission of Premier Oil PlC.
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The different types of metals and their range of use in C02 and H2S,as a function
of the partial pressures, is illustrated in the diagram below.
1000
~~/,"'._. <, - ',_ - ',' - - _: ":, , "" - : 'I1~-.~':J~o, '. " " ~
"if~~~~ J'Qlu;:-:~oj:'f~r~5, ,- -_~~ ~~.,
~~;:;~j"~o1
100m
27% a- -31%1'1 - 3.5 %Mo
27%a 42%N - 3%Mo
i'I:S
'Cij 1 00~N
8
4.3.2 Sealing systems
u..0 10wc:
(I')(I')
11w API J-SS
I
APll-80c:N-80 G-75.
....I
b: 0.1
I I
O_O1l
CE
0.05 psi
0.001I I I I
0.01 0.1 1 10 100 10m 100m
PARTIAL PRESSIJtEOF H2Spsia
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 19
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Seal failure to fluids is a frequent cause of malfunction in completion equipment.
When determining sealing material requirements for a completion it is essential to
consider the produced fluids, completion fluids, acids and chemicals, corrosion and
scale, as well as the temperature and pressure. The sealing materials most
commonly used for both downhole and surface equipment are elastomers and
polymers. Varieties of these are available for different dynamic and environmental
requirements.
Unlike most plastic materials, elastomers have the ability to recover from quite
significant stress-induced deformation. Because of their incompressibility, they
deform in constant volume so that in a restricted housing they provide a positive
sealing force. In addition, their elasticity gives them good conformance to any
roughness in the metal surfaces that they are sealing.
As the first step in determining the sealing requirements for a well completion, the
working conditions in which the equipment is to be used must be accurately
defined. The minimum information required to design the sealing system for a
completion is tabulated below.
DATA REQUIREMENTS
PARAMETER CONDITIONS
Closed in/flowing
Surface and bottom hole temperatures Maximin
Static/cyclic, frequency
Reservoir pressure Depletion/Abandonment pressure
Wellhead pressure Closed in/flowing
Pressure profile Variation, frequency, rate
Production fluid composition Hydrocarbons, aromatics, water
Gas/oil ratio
Injected fluids composition Strength, duration, frequency
Inhibitors Corrosion and scaleControl l ine fluids
Completion fluidsAcids, alcohol and chemicals
Temperature of injected fluids downhole
Produced gas composition Hydrocarbons, hydrogen sulphide, carbon
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Elastomers are not subject to corrosion and their elasticity allows sealing between
rough or uneven surfaces, so that in many applications they are more appropriate
than metal seals. The more commonly used oil-resistant and non oil-resistant
elastomers are tabulated below.
Elastomer types andcodes
sulphide, carbon dioxide
Differential seal pressure Level, rate, frequency
Seal movements Travel, rate, frequency
.Lifetime required between workovers
1. Non oil resistance - General Purpose
ASTM Code Elastomer Class Example
NR Natural rubber SMR
2. Non oil resistance - medium heat resistance
ASTM Code Elastomer Class Example
EPDM Ethylene-propylene-diene (unsaturated) Nordel
3. Oil resistant - Low temperature
ASTM Code Elastomer Class Example
TR Polysulphide Thiokol
AU/EU Polyurethane (ester/ether) Adiprene
4. Oil resistant - General purpose
ASTM Code Elastomer Class ExampleCR Chloroprene rubber Neoprene
NBR Nitrile rubber Buna-N
HNBR Hydrogenated Nitrile rubber Therban
CM Chlorinated Polyethylene Duralon
CSM Chlorosulphonated polyethylene Hypalon
CO Epichlorohydrin Hydrin-100
ECO Epichlorohydrin copolymer Hydrin-200
5. Oil and heat resistant
ASTM Code Elastomer type Example
ACM Polyacrylic VamacFCM Tetrafluoroethylene -propylene Aflas
FKM Fluoroelastomer Viton
FFKM Perfluoroelastomer Kalrez
6. Silicone rubbers
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Most sealing systems for both static and dynamic conditions are based on eitheraxial or radial compression. For these, the maximum pressure that can be
contained by a seal is determined by the force that it exerts against the sealing
surface. The resulting interfacial pressure between them defines the maximum
applied pressure that the seal can hold. In pressure energised seals, the seal
rating is enhanced by using the contained fluid to increase the interfacial pressure.
4.4.2.1 a-rings
These are designed for static radial compression and are usually fitted into arectangular-profile seat, if necessary with a rigid back-up ring to prevent extrusion
at high pressure.
4.4.2.2 T-seal (GT ring)
Used in hydraulically operated safety valves and in dynamic reciprocating service
to avoid spiral failure due to twisting. T-seals incorporate one or two thermoplastic
back-up rings to give extrusion resistance in both directions and to prevent
rotation.
4.4.2.3 Chevron V-packing and bonded seals
V-packing seals are designed for the dynamic or semi-dynamic conditions of
expansion joints and sliding sleeves. They are also used for stab-in systems and
as external seals in wireline-retrievable safety valves, gas lift valves, packer
stingers and locks. Different elastomers and plastics are combined into a pressure
energised multi-ring V-stack set. V-packing and bonded seal compounds can be
fibre-reinforced for additional strength. Typical O-ring and chevron packingarrangements are illustrated on the next page.
ASTM Code Elastomer type Example
SI Silicone rubber
FSI Fluorosilicone rubber
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o Ring sack
4.4.2.4 Packer elements
Seal Types
Chevron seal
0- Rng MtOtt!l :!de~or
EleeJX:irnel eeal
Packer elements
Packer elements are large elastomer rings that are energised by axial deformation
- as the packer sets the element is extruded against the casing surface. They are
used to isolate the static radial pressure of the production zone from the annulus.
Swelling of the elements can cause difficulty with retrievable packers, requiring
excessive pull to unset them.
. Temperature
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Short term exposure to high temperatures will soften elastomers and reduce their
mechanical properties. However, longer term exposure causes hardening with a
drastic loss of elasticity that can lead to embriUlement. As the performance of a
seal can be significantly reduced by an increase in temperature, the limiting value
will depend on the application. Provided that an adequate back-up ring has been
installed, a static seal can still perform effectively after losing 60% of its strength.
However, dynamic seals are much less tolerant because they are prone to tearing
and extrusion.
. Aggressive conditions
Elastomer selection becomes more limited in moderately aggressive wells with
pressures up to 10,000 psi and temperatures around 300°F. This is particularly so
in the presence of C02. which, together with water, can cause explosive
decompression of an elastomer seal? Because higher temperatures and pressures
demand a more extrusion-resistant elastomer, seals and back-up rings must be
specially formulated to resist decompression and extrusion. H2S not only causes
corrosion of metal seats but reacts with Nitrile elastomers, the extent depending on
temperature, H2S concentration, elastomer grade and seal thickness - the thicker
the seal the longer it will survive in an H2Senvironment.
As a general guide, temperature should not exceed 200°F for Viton or 150°F for
Nitrile. Above these limits, elastomers with superior amine resistance should be
used. Aflas compounds are preferred for compression seals like O-rings and T-
seals that will be exposed to inhibitors and can be used to replace fibre-reinforced
Nitrile V-packing and Nitrile packer elements. Using the higher quality Aflas
material depends on the presence of inhibitors, the seal type and the temperature.
. Highly aggressive conditions
High concentrations of H2S and C02 in high temperature (450°F) and pressure
(10,000 psi) environments require the use of optimum materials in a completion
system. Aflas compounds are appropriate for O-rings, T-seals, V-packings and
packer elements, unless cyclic thermal conditions or less than 70°F are expected.
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Date 1/3/98
Ref.
In such situations Kalrez or Chemraz perfluoro-elastomers can be used for o-rings,
T-seals and V-packings, but are not yet available for packer elements, which are
therefore restricted to Atlas. Back-up rings must be used with Atlas, Kalrez and
Chemraz O-rings.
Prep.by : IESL Section No.
Revision: A
Page No.: 25
Version: 1
Guidelines to Well Completion Design
RDS Resource - Premier Oil Pic
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\) 4.5 Types of completion
The many types of well completion can be grouped in three basic categories:
barefoot or open hole, slotted liner and cased/perforated completions.
4.5.1 Open hole completion
In a barefoot or open hole completion, the lowest casing is .set above the reservoir
with the lower section of the wellbore left uncased. Consequently it can only be
used in a consolidated formation. This widely used technique is the simplest and
cheapest because no equipment has to be installed. However, it allows no
selectivity of the reservoir zones either for production or injection. For a producing
well this means that water or gas break-through cannot be controlled. In an
injection well, any wide variation in permeability will result in the injection fluid
preferentially entering the most permeable zone, so preventing an effective sweep
of the lower permeability zones. The main features and limitations of the open hole
completion are:
Advantages. Lower equipment and operating costs
. Maximum well productivity and minimum formation damage
· Preferred option for horizontal wells
Limitations · Should only be used in consolidated formations
· No zone selectivity or flow control of gas or water production
· Wellbore may require periodic cleaning and maintenance
4.5.2 Slotted liner completion
This is a variation of the open hole type in which a slotted tubular string is used to
control the influx of solids from a weak or poorly consolidated formation. In most
cases the tubular is a liner hung off from a packer or conventional hanger, with the
slots sized for the type and size of formation solids expected. A slotted liner is
used where the particle size distribution corresponds to a homogeneous formation,
or for a weak but not wholly unconsolidated matrix. The features and limitations of
Date 1/3/98 Tprep.bY:ESL lRef.
Guidelines to Well Completion Design
RDS Resource - Premier OilPIcJSection No.
Revision: AJPage No.: 26
Version: 1
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purpose whatsoever includi ng conceptual design, engineering, manufact uring or construct ion without the express wri tten pennission of Premier Oil PLC.
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a slotted liner completion are similar to those of the open hole system, but have as
additional advantages:
. Provide mechanical stability to the wellbore
. Give limited control of produced solids
. Haveminimum reduction in the flow area and hence productivity
4.5.3 Cemented and perforated casing/liner
In this technique a casing or liner string is run and cemented across the production
interval, and then perforated in selected zones. Although this is the most
complicated method, hence time consuming and expensive, it offers good zonal
isolation and wellbore integrity with flow control of produced water or gas. The
main features and limitations are:
Advantages. Better zonal isolation and flow control
· Reduced productivity
Limitations · Time consuming and expensive
· Greater potential for formation damage and impaired
productivity
The three types of completion are illustrated on the next page.
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Completions can be classified by other criteria such as production method (natural
flow or artificial lift), or the number of zones to be completed and their location
(onshore, offshore, subsea). Two these classifications are shown in the schematic
below.
PUMPING
. Oil Wells
. Wet gas wells Hydraulic
Temporary
Tubingless
Low cost
Single zone
High pressure
FLOWINGHigh rate
. Gas wells
. Oil wells
. Wells on gas lift
Liner PBRs
Tubingless
Low rate
Single string
MultizoneHigh rate
Parallel
Concentric strings
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Significant differences between onshore and offshore well completions largely relate to
the surface interfacing rather than the completion itself. However, each set of
circumstances must be evaluated in developing a suitable completion philosophy and
detailed design. The effects on completion design of the differences between these
operating environments are reviewed below.
Completion cross-reference accordinQ to operatinQ environment
In recent years, the development of more reliable and cost-effective technology has
seen the successful introduction of such innovative concepts as multilateral and
multifunctional wells.
Location I Onshore Offshore SubseaConsideration
Cased & perforated Cased & perforated Cased & perforated
Completion type Open hole Slotted liners 1 Slotted liners1Slotted liners
Design philosophy Lower cost & productivity Productivity and safety Productivity and safety
Well performance IPR and VLP IPR and VLP IPR and VLP
Artificialliff Method selection Method and interfaces with Production tree and hanger, riser
and logistics the platform systems and interfaces,
Sand production Can be managed if Manageable depending on Critical, not allowed< 50 Ibs /1000 bbls the installation capacity
Tubing design - Conventional DSF1 Conventional DSF1 Priority to collapse criteria,
Mechanical loading unless special conditions unless special conditions annular pressure needs toare specified are specified be bled off
Erosion Only in special Critical Critical
circumstances
Corrosion Depending on severity, Material selection Material selection
mainly prevention program
Safety valves Not always required Always required, tubing or ubing retrievable preferable based orwireline retrievable hydraulics and reliability record.
Critical item
Packers Packerless is common Mainly packer type, other Packer typeunless is HP or gas well in particular circumstances
Nipples Minimum amount Functionality Functionality
Formation Isolation Depending on the nature of Depending on the nature of Recommended depending onvalves the potential damage the potential damage. interfaces with well functions
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Multilateral wells in particular, have very effectively scaled down features of
horizontal well technology to suit the reduced diameter of their main wellbore,
although cost and limited equipment options have slowed implementation. The
multilateral concept was first developed in Russia during the 60s, but had to be
abandoned because of prevailing technological limitations.
Multifunction wells carry out more than one function with little modification to the
main wellbore. This most commonly involves producing up the tubing while
injecting down the annulus. In completion terms, this is an efficient option that, if
properly managed, would reduce the number of wells required to develop a field.
Some of the main completion issues to be addressed for a multifunction well are:
. Mechanical loading on the tubing, particularly due to collapse
. Axial movement of the tubing string due to temperature changes
. Well barriers and safety philosophy
. Erosion and corrosion of tubing and casing, both internal and external
. Operating and well maintenance philosophy
. Equipment sizes and performance expectations long term.
Intelligent or Smart wells are the latest advance in hydrocarbon production and
may include multilateral or multifunction wells. Their concept of minimum well
intervention for maximum control, initially developed for subsea wells, depends on
installing in the well a considerable quantity of subsurface electronic data
gathering/transmitting and control equipment. Completion design for these wells
requires a proper definition of the functions and long term production strategy as it
must accommodate the downhole controls that are surface operated. In most
cases, flow from particular intervals is controlled by a series of hydraulically
operated sliding sleeves, with signals transmitted to remote operating points
through special cables and conduits.
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5 RESERVOIR AND WELL PERFORMANCE
5.1.1 Well Inflow Performance Relationship
The well Inflow Performance Relationship (IPR) quantifies the changes in pressure
and flow rate as the reservoir fluid passes form the reservoir into the wellbore. The
IPR was developed from Darcy's Law which defines the velocity of a fluid as a
function of: the rock permeability, the fluid viscosity and density, the change in
pressure along the fluid path and the change in elevation. Darcy's Law makes two
important assumptions. Firstly, flow is assumed to be linear, Le. that the cross-
sectional area of flow is the same regardless of the position within the rock. As this
clearly is not the case within a reservoir, a modification is required to approximate
the flow area of a reservoir. Secondly, flow is assumed to be laminar, Le. that all
the fluid 'particles' are moving in straight lines, even though different streams or
layers may be moving at different velocities. The Darcy's Law equation is:
Q/A= kill ( dP/dl - p 9 dD/dl ) .Eq.
Other important considerations for the development of IPR curves are: well
drainage area, fluid type (compressible or incompressible), productivity index and
the effects of skin.
5.1.1 Radialflow- steady state
Production wells drain a specific volume of the reservoir, with flow converging to
the wellbore at the centre. With a constant flow rate, this convergence causes the
fluid velocity to increase towards the wellbore. In a radial flow model to account for
this, the linear flow area is modified into a cylinder in which the flow is from the
outer wall to the centre. Expressing Darcy's equation in radial coordinates, the
change in pressure can now be defined in terms of the reservoir and wellbore radii.
In field units:
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On the next page, a graph of reservoir pressure (Pr) versus the radius (re) of a
producing reservoir shows the decline in fluid pressure as it reaches the wellbore.
The pressure difference (Pr - Pw) is called the drawdown. This version of theDarcy's equation assumes an infinite drainage volume for the reservoirs (Le.
steady state) so further analysis is required to determine the drawdown in a semi-
steady state system. Other factors involved in the development of IPR curves are
detailed below.
5.1.2 Compressible fluids
Although water and oil can be reasonably assumed to be almost incompressible,this is not the case for fluids with a gas content. Predicting inflow performance for
gases is more complex because it is dependent on the gas temperature and
pressure. The general equation for the inflow performance of a gas system is:
Where
Pr Reservoir Pressure psi
Pw Wellbore Pressure psi
qs Flow Rate STB/day
Fluid Viscosity cp (centipoise)
B Fluid Formation Volume Factor dimensionless
K Permeability of the Reservoir md (millidarcys)
h Thickness (depth) of Formation ft
re Radius of Depleting Reservoir in or ft
rw Radius of the Wellbore in orft as re
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-2d 3.9764.10 .K-h.T .Zr_ S S.P.dP
r Qs'Ps'T'Z'J.l Eq.
Both gas viscosity (IJ)and the gas deviation factor (Z) are functions of pressure,
but by substituting the standard condition terms (subscript s) a real gas pseudo-
pressure function m(P) or \jf can be derived. Analysis of inflow performance for a
gas is more complicated than for an incompressible fluid, but the software
package normally includes a number of simplified solution techniques
CI)...~I/)I/)CI)...Il.
Pw
rwDistance from Wellbore
r .:IEffect of Drawdownl'
- -...J OUl
/ down-- - ,
/I(
)amaged Zone
,--
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 33Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1
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5.1.3 Non-Darcy flow
Although Darcy's law applies only to laminar flow, it is generally valid for most oil
wells. However, in gas wells and some very light crude oil wells the producing fluid
can be in turbulent flow. For this situation is used the Frochheimer equation - a
Darcy modification - which includes a viscous flow term:
dP_/l'u + l3.p.u2 ..Eq.K .....................
Here, the pressure distribution in the reservoir becomes a quadratic function of the
velocity. The non-Darcy component due to turbulent flow is usually treated as an
additional pressure loss.
5.1.4 Productivity Index
The Productivity Index (PI) defines the ability of the reservoir to deliver fluids to the
wellbore. With units of STB/day/psi, it is simply the flowrate divided by the pressure
drawdown:
PI- q s
P e- Pw .Eq.
5.1.5 Skin factors
A wide variety of skin factors have been established to account for impairment of
reservoir performance by various external causes during drilling and completion of
the well. These, with the formulae for their calculation, relate to not only the
completion type, but also to such as well geometry, formation geology, the effects
of drilling and completion operations and the perforation equipment.
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· Perforation skin is the loss in pressure when reservoir fluids pass
through the perforations. In wells where there is no significant damage at the
wellbore or caused by the perforation, it is a function of the wellbore radius,
the perforation density, phase angle and tunnel length. It is normally
subdivided into vertical, horizontal and wellbore components.
· Compactionskin is the perforation induced skin that affects the rock
surrounding the perforation tunnel. It is a function of the crushed zone
permeability and is the log of the ratio of the crushed radius to the perforation
radius.
h
(
k
) (
re
)
S = I.In-
C LP k e r p Eq.
· Damage skin is the damage caused to the formation round the wellbore
by the invasion of filtrates during drilling that can seriously impair the
productivity of a completion. It is a function of the permeability and radius ofthe damaged zone.
(
k
) ( (
r d
) )
kSd= - - 1 . In - + S + -.s x
kd rw P kd ..... ...... .. .. ... .... .Eq.
Definition of the nomenclature can be found in the texts[XI.
The change in IPR from an ideal to a more realistic model as various skin effects
take effect round the wellbore is depicted in the following graph.
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5.1.2 Vertical lift performance
The vertical lift curve is a property both of the completion geometry and the
reservoir fluids as they exist in the formation. Its mathematical form follows the
laws of conservation of energy with different energy components as defined below.
By plotting flow rate against pressure, system curves can be established that are
used to determine the optimum production rate for a given system.
5.1.2.1 Tubing performance
By applying the conservation of energy principle a mathematical expression can be
derived to describe fluid flow in a pipe, the sum of the energies being zero. The
energy components are:
. Internal Energy - a function of the entropy and enthalpy of the fluid
. Energyof Expansion/Contractiona functionof the pressureandvolume
. Kinetic Energy - dependant on the fluid mass and velocity
. Potential Energy - defined by the depth at which the fluid is located
. Work -additional energy added to the system, e.g. by artificial lift processes
These factors are represented across the system as pressure drops whose main
components are identified using the equation:
Where:
~Ptubis the pressure drop in the tubing
~PhYdis the hydrostatic gradient
~Pfrcis the pressure drop due to the frictional forces
~Pkeis the kinetic energy pressure drop (typically 1% of the total)
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The ultimate goal is to minimise the level of energy required to flow
hydrocarbons from the wellbore to the surface at a flow rate that is
operationally realistic and commercially acceptable.
5.1.2.1 Tubing size
A factor that can be altered to optimise production rates is the tubing size. High
fluid velocities in small tubing sizes increase the possibility of erosion and friction
pressure losses. Larger tubing sizes reduce velocities which, in two-phase
hydrocarbon production where pressure is below the bubble point, allows
significant slippage between the gas and liquid.
-Gas-Liquid Ratio
The gas-liquid ratio (GLR) affects the hydrostatic gradient inside the tubing
because an increase in the ratio of gas to liquids reduces the hydrostatic pressure.
However, at high liquid rates the total gas volume will be so large that the pressure
gradient increases to reflect a rise in friction pressure. By contrast, for a low water-
oil ratio (WOR), there is an increase in both the density of the mixture and the
slippage, hence also in the hydrostatic head and friction pressure loss.
Combining the IPR and VLP gives the completions engineer information on:
. Maximum productive capacity of the reservoir- also defined as the absolute
open-hole flow (AOF)
. Pressure behaviour of the production fluids from wellbore to surface behaviour
can be determined for changes in GOR, WOR or tubing size. Accurate calculation
of these parameters by available software packages provides solution points for a
wide range of well conditions. This allows the engineer to simulate well
performance later in the field life when reservoir pressure has declined, either to
assess potential revenue or any requirement for pressure maintenance. The
impact of tubing size on well performance is reviewed in more detail in Section 6.
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5.1.3 Developing a well performance model
As one of the first steps in the completion design process is to develop a well
model, this section reviews the fundamental steps that should be taken. However,
the methodology presented is only one of several possible approaches that may
be considered.
Step 1 - Information gathering
As in any other engineering task, the starting point for an analytical process is the
gathering of data and information. In this case, the reservoir information required
includes drive mechanism, depth, thickness and geology of the production interval
and the fluid temperature and pressure. The reservoir fluid characteristics,
especially PVT data, are of primary importance in developing a representative
reservoir model. Also required are details of the well geometry with the types, sizes
and depths of casing strings. Local regulations and environmental constraints must
also be considered as they might have a major impact on the design process.
Step 2 - Understanding reservoir behaviour
This involves defining a representative inflow performance relationship (IPR) and
developing a production strategy that will give maximum productivity and recovery.
Sensitivities such the IPR response to differing levels of formation damage,
various skin factors and variation of such fluid characteristics as GOR and WOR
should be reviewed at this stage. Evaluating the reservoir performance will allow
the completion engineer to identify the best way of establishing communication
between the reservoir and wellbore. Also to be considered are the reservoir
geomechanics, determining the field stress and perhaps even at this stage
defining the tectonic influences. The geomechanical conditions will allow the
engineer to consider which completion option - open hole, slotted liner, or
cased/perforated - can be used for the development.
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Step 3 - Defining the flow path and its characteristics
The vertical lift performance (VLP) curves should be used to develop the normally
tubing-based flow path system and its components. Nipples and safety valves
should then be reviewed to determine the pressure-energy needed to produce the
well without artificial lift. A sensitivity analysis similar to that in Stage 2 should be
performed to assess the overall performance of the whole system of reservoir and
flow path.
Step 4 - Determining the completion configuration across the reservoir
section
As there should by now be a fairly clear picture of the reservoir capacity, the fluids
it will produce and their optimum flow path, the completion configuration across the
reservoir section can be decided. The design philosophy adopted will now allow
provisional selection of appropriate equipment and methodologies depending on
whether there is a horizontal section, the completion is to be open hole for
maximum productivity, or if flow control and isolation are required.
Step 5 - Integrating reservoir and tubing performance
At this point, a preliminary run of the pressure- and flowrate-based IPR vs VLP
graph can be made to evaluate the potential system performance. Sensitivity of the
system to possible reservoir changes throughout the field life should now be
determined, and any necessary compromise reached by an iterative process.
Artificial lift options such as electric submersible pumps and gas lift can also be
evaluated now.
Step 6 -Detailed component selection
The rest of the design process concentrates on detailed selection of the individual
system components. Such as packers, nipples and safety valves are chosen
according to the requirements identified in the preceding steps.
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6 SYSTEM AND COMPONENTS DESIGN
Oil and gas wells and their hardware must be regarded as a single system that
includes both reservoir isolation (by casing) and the completion string. These
elements of the system are interlinked so that the features and characteristics of
one affect the other. The main considerations for selecting a particular component
of the system are reviewed below.
6.1 Tubing Design
--
The primary functions of the tubing string are to serve as a flow conduit for
production, injection and maintenance/treatment fluids while maintaining pressure
integrity under all likely operating conditions.
6.1.1 Hydraulic performance
The Vertical Lift Performance (VLP) - or outflow curve - represents the hydraulic
performance of a tubing string by showing the pressure difference between
sandface and surface. The tubing hydraulic performance depends on such diverse
variables as the tubing size, well depth, PVT of the production fluids, GOR and
water cut. As most oil and gas wells produce a mixture of gas and liquids, the
hydraulic performance calculations must include multi-phase flow for an accurate
evaluation of the tubing as a part of the whole well system. The calculations,
primarily of pressure losses in the flow conduit between reservoir depth and the
surface, are based on three main factors:
Gravity
Friction
Acceleration
[ g I gc p Cos 8 ]
[ f p V 2 I 2 g c d ]
[ p v dv I gc dZ ]
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-
Numerical integration of these terms for each tubing section gives the total
pressure difference between reservoir and surface. The gravity term is
predominant for single phase liquid production, but multi-phase systems require
complex techniques to determine the partitioning of hydrocarbon mixtures into gas
and oil phases. While hold-up effects, slippage between phases and fluid densities
can be determined from PVT correlations, friction accounts for a large part of the
overall head loss in high rate wells. The loss due to friction is normally in the range
5 - 25% but is occasionally more. The acceleration term usually arises from fluid
expansion as pressure decreases towards the surface. Computer programs such
as PROSPER and WELLFLOW are generally used for this type of computation in
completion design. A NODAL analysis approach treats the well as a single system
and integrates reservoir performance (IPR) and the VLP-based tubing hydraulic
performance. Detailed descriptions of IPR and VLP are given in Section 5.
6.1.2 Mechanical loading
It is essential that the mechanical attributes of tubing options are carefully
reviewed to confirm their integrity under the expected operating conditions.
However there are still significant uncertainties about these conditions that could
affect the loading on the tubing. Despite the availability of analytical tools, tubing
design has been mainly based on a semi-analytical approach. There are no
universally accepted standards for tubing design although some national
regulatory authorities specify minimum design criteria. As a result, each
manufacturer has an individual design philosophy.
A number of analytical tools are now available for carrying out rigorous analysis of
the loading that would be applied under particular operating conditions. As these
should be used wherever possible, the analysis for a subsea well is given in
Appendix **. Tabulated below is a typical set of tubing design criteria that includesrecommended design factors for the most common operating conditions.
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TUBING DESIGN CRITERIA
CONDITION I
Burst
T DESIGN FACTOR
Flowing wells
Fracturing strings
Collapse
Flowing wellsw/Packer/PBR
Tension
All wells
Wells w/packers
or anchors
Compression
All wells
Total Triaxial
LOADING
Internal
External
Additional considerations
Internal
External
Additional considerations
Internal
External
I DESIGN CRITERIA
Kill pressure on hydrocarbons filled tubing at
squeeze rates> 2 ft/sec.
Packer f luid and no annulus pressure
Pressure test and stimulation operations
Screen-out with max. sand concentration and
maximum pump pressure
Packer fluid and specified casing pressure
Pressure test prior to the operation
Tubing empty to lowest possible fluid level
Pressurised packer fluid in the annulus
Additional considerations I Check biaxial effects of tension on large 0.0.
pipe. Pressure tests
1.125
1.125
1.125
Body 1.5Joint 1.8
Body 1.3Joint 1.5
Body 1.3Joint 1.5
Body 1.5
Joint 1.8
1.67
1.25
Running & Pull ing
Additional considerations
Packer release
Anchor release
Additional considerations
Operating loads
Additional considerations
I
Axial loads
Additional considerations
Stress
Check effects of temp. &
pressure changes for
pressure test ing, well ki lland stimulation
Additional considerations
Bouyant weight in completion f luid
Drag forces particularly in deviated wells.
Age and corrosion effects on the pipe
Buoyant weight of pipe in workover fluid
Shear pins type, number & rating.
Age and corrosion effects on the pipe. Stuckseals
Effective tension at surface
Pressure test on plugs above packer/anchor
Cool down during stimulation of well kill.Packer or seal release
Piston forces on swedges
Combined set down and operating loads
Total triaxial load
Normal operating conditions
(Production / Shut in)
Maximum loading conditions occurring
infrequently (Well kill/stimulation)
Permanent buckling
Piston forces on swedges and PBRs
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Tubing strings rarely fail during routine production operations except through pipe
deterioration resulting from corrosion, fatigue, or underestimation of the thermal
effects in high temperature wells. Failures are most commonly caused by
operating personnel neglecting to take corrective action in a high pressure
situation during either production downtime or high-cost operating conditions. The
most severe loading occurs during such operating conditions as:
. Running and pulling the completion
. Pressure testing the string
. Well kill and stimulation operations
. Perforating and production start-up
-- The strength of joint couplings must be analysed separately. Strength values for a
variety of premium threads are tabulated below.
STRENGTH OF PREMIUM COUPLINGS (Ib/tt)
SIZE [ In ] 2 3/8 2 7/8 3 REMARKS
WEIGTH [Lblft ]
GRADE J55 L80 J55 L80 J55 L80
HYDRIL
CS 72000 104175 100125 145125 142200 207225
A95 67950 98100 87975 128025 133200 194175
501 72000 104175 100125 145125 142200 207225
CFJ-P 47025 67950 66150 95175 96075 139050
VAM 72000 104175 100125 145125 142200 207225
API EUE 72000 104175 100125 145125 142200 207225
APINU 49050 72000 73125 105975 159075 159075
NK NK25C 72000 104175 100125 145125 142200 207225
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6.1.3 Corrosion considerations
As corrosion effects were not covered in the review of equipment materials and
sealing systems in Section 4.4, basic guidelines for wells liable to corrosion are
presented here. Tabulated below are the main characteristics of the six basic
types of corrosion.
-
TYPE \/IECHANISM(S) CONDITION PARTIAL MECHANISM REMARKS
PRESSURE OF CONTROL
[psi]
Sweet (CO2) Mesa or pitting Severe > 30 Material selection Avoid high turbulence areasCommon >10 CoatingRare >7
Sour (H2S) Stress cracking 0.05 Material selection Reduced at high temp.
Weight loss Salt water 50 Chemical inhibition, Barnacle type of scale not
SRB Anaerobic Material selection seen in caliperswater
Chloride(CI) Pitting CI cone. High chrome alloy Reduced
Velocity Inhibitors Temporarily controlled
Low pH Hea CP
Oxygen(O)
Mixed
Galvanic!
Electromagnetic
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6.2 Flow controls and isolation
Of the various types of flow control and well isolation equipment used in oil and
gas wells, the principal and most common is the safety valve. Initiallydesigned to
be self-regulating - Le. subsurface controlled - technological development has
evolved the widely used surface-controlled safety valve that allows shutting-in of
the well in an emergency. Selection of these and other components such as
packers, plugs, chokes and nipples depends on the particular well conditions, local
regulations and company policy.
6.2.1 Safety valve selection
.... During the early years of the oil industry, drilling and production operations
suffered many blowouts that resulted in a uncontrolled flow of fluids. When
operations started to move into sensitive areas and the first high pressure wells
with toxic gases were being drilled, it became necessary to have a method of
safely controlling a blow-out without operator assistance. As the surface systems
that were developed initially depended on the wellhead remaining intact, it was
clearly essential to have a fail-safe means of subsurface well control. The main
functions of a subsurface safety valve are:
. Protect personnel and equipment
. Contain toxic gases
. Prevent pollution
. Protect reserves by eliminating loss through uncontrolled release
The schematic below shows the main types of safety valve in use, usually
categorised by the retrieval method and control mode.
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SAFETY VALVES
[' T r Ti INJECTION GASVENT GASVENT TUBING/ ANNULUSi SAFETYVALVE SAFETYVALVES SAFETYVALVES SAFETYVALVES
I CONTROLLED CONTROLLED
_~ l=-=I:::~::::,:~~
Subsurface Controlled Subsurface Safety Valves (SSCSSV)
Also, know as velocity valves or storm chokes, these were the first types to be
developed. Because their closure mechanism was dictated by the downhole
environment, they had several disadvantages:
. Substantial reduction in flow area
. Over-sensitivityoalternatingwell conditions
. Unresponsive to small surface leaks
. Difficulty of calibration
SSCSSVs were actuated by changes in well conditions-either the differential
pressure through a velocity type valve, or the tubing pressure at an ambient
pressure type.
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With a choke or 'bean' to create a throughput differential pressure, the velocity
valve was held open by a calibrated spring so long as the downhole back pressure
remained above the set value. A drop in back pressure changed the pressure
balance and generated enough force to overcome the spring. The valve assembly
often included equalising subs so that the valve could be reopened without having
to pull it out of hole.
In ambient pressure valves, when tubing pressure equalised with an atmospheric
or pressurised chamber a spring created an imbalance that closed the valve.
SSCSSVs are rarely used today.
- Sub surface controlled sub-surface safety valve (flapper type)
OPERATING PRINCIPLE
Inc'e ",,'od\, "'IOUI/>'"r~lzlclon taLeli!!t.rn Inclf:lltl!bd
p"' '" drop "'...ng a,. ",OIonup I !IQoIMla, . ' !" '' lI d o~ng d, .
ftoppOI.
Seal
Restriction
Spring
Piston
Flapper
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Surface Controlled Subsurface Safety Valve (SCSSV)
During normal production or injection operations, these valves are held open by a
pressurised hydraulic passing down a control line external to the tubing. The line
connects from the wellhead to the hydraulic control panel of a surface emergency
shutdown system. This panel allows the operator to control the activating
pressuresonthe surfaceandsubsurfacesafetyvalves.An EmergencyShut-Down
Loop (ESD) may have thermal sensors, high-lowpilots and manual shut-down
stations. SCSSVsare classified as either wireline- or tubing-retrieved,alternate
designationsfor the latterbeingTRSCSSVor TRSV.
Wireline Retrievable safety valves are deployed on a dedicated running tool to be
installed in an appropriate landing nipple. Their advantages and disadvantages
are:
-Advantages
. Accessibility - can be installed in hydraulic landing nipples, ported
communication nipples or locked-out tubing retrievable subsurface safety valves.
. Easy installation and removal for replacement or maintenance
. Removable during severe workover operations such as acidizing or fracturing.
Disadvantages
. Mayhave to be removed during wireline operations
. Flow rate restricted by the smalier-than-tubing ID
. When closedmaybe blownfrom nippledue towirelineoperatorerroror faulty
locks
. Control line fluid exposed to contaminating fluids in tubing before valve is
landed in the hydraulic nipple
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Tubing retrievable safety valves are made up on the running string and run in
hole with the completion. Their advantages and disadvantages are:
Advantages
. No restriction of flow rate as ID matches the tubing
. Wireline operations can be carried out through the compatible ID
. In the event of tubing retrievable valve failure a wireline valve can be landed in
it
. Control line fluid not exposed to well fluids during installation and retrieval
. Valve can be bridged during severe workover operations.
-Disadvantages
. Inaccessibility- thetubingmustbe pulledto retrievethevalve.
Safety valve selection factors
As the primary function of the subsurface safety valve is to close when required,
this must not be impaired by additional features that may have been incorporated.
To ensure this, any such features must be of simple design, rugged and reliable. A
number of factors must be considered in the valve selection process.
Flow Rates
The effect of flow rate through the valve depends on whether the fluid produced is
gas, liquid or multi-phase, the maximum flow rate being a function of production
pressure and the specific gravity of the fluid. Thus, the corrosion potential - and for
wireline retrievable valves, the pressure drop - must be considered along with any
solids that may be carried by the fluid. The protective surface film laid down by
corrosion inhibitors might limit the production rate as higher fluid velocities would
tend to continuously remove the film, incurring the risk of both corrosion and
erosion. Any restriction of the maximum flow rate therefore reduces the maximum
allowable velocity requirement for the valve. The variability of such factors from
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well to well precludes a simple rule for determining the maximum flow rate through
a safety valve, but API RP 14E contains references for their estimation.
Setting Depths
The setting depth of a safety valve is critical as it dictates the minimum pressure
required to ensure closure of the valve under worst case conditions - e.g. parting
of the control line requires the valve to close against the hydrostatic head of the
annulus. Increased setting depths are necessary in such different applications as:
. Water depths exceeding 2000 feet
. With paraffin or scale problems the valve should be placed below deposition
level.
. In Arctic operations the setting depth must be well below the permafrost zone
. Subsea wells require deeper setting depths to avoid hydrate formation in the
lower temperatures.
Size
Because equipment must fit into the casing while providing an adequate path
through the valve for produced fluids and service equipment, it is important to
know the casing program as well as the tubing data. It is as necessary to define
the bore of nipples in the tubing string above the valve as it is is for the tree and
hanger, because these IDs determine the accessories required.
Pressure
The working pressure rating of a safety valve is the maximum continuous
operating pressure to which it should be subjected, although control lines can
safely exceed that value.
Pressures over 10,000psi: Elastomer and plastic seals should not be used in this
environment, because their failure is now recognised as the primary cause of
equipment malfunction.
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 54
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
This document contains CONF IDENTIAL an d PROPRIETARY INFORMAT ION of Pr emi er Oil PlC. This document and the information disclosed within shall not be reproduced in whole o r in par t to any thi rd party any
purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express wri tten permission of Premier Oil PlC.
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Environment
In extremely hostile environments, even at lower pressures it may be necessary to
utilise metal-to-metal seal technology. Resilient seals are responsible for the
majority of equipment failures as the harsher the environment the shorter their life.
A valve recommendation cannot be made without knowing such critical data as
well pressure and temperature, H2Scontent and free chlorides.
Typical design features
The following types of safety valve are supplied by major manufacturers such as
Camco, Baker and Halliburton. It should be noted that design changes are
continuously being made in response to technological advances.
-- Ball type - A steel ball with a vertical axial hole of the same ID as the valve, rotates
on its horizontal axis for closure. Rapidly being replaced by the flapper system.
Flapper type - The flapper is not directly attached to the flow tube but is set just
below it and pivots the mounting point. This makes it easy to pump against them
for a well-kill operation and maintain well integrity afterwards. (See illustration
below)
Date 1/3/98 IPrep. by: IESLRef.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision: A
Page No.: 55
Version: 1
This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PlC. This document and the infonnation disclosed within shall not be reproduced in whole o r i n par t t o any t hi rd par ty any
purpose whatsoever Including conceptual design. engineering, manufacturing or construction without the express wri tten pennisslon of Pr emi er 01 1PLC .
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Concentric piston actuation type - The large hydraulic area generally prevents this
type of valve being deep set. Because seal friction increases with pressure so also
does seal erosion.
A flapper type surface controlled sub-surface safety valve is illustrated below.
Surface Controlled Sub-Surface Safety Valve (flapper type)
OPERATING PRINCIPLE
Loes ci h)l:haulic pressurealbwa spring top ush the piston
up .closng the lIapper valve
~ydrauliccontrol line
....
islon
Seal
Date 1/3/98 IPrep.by: IESL I Guidel ines to Well Completion Design ISection No. IPage No.: 56Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
This do cument c ont ains CONF IDENT IAL and PROPRIETARY INFORMAT ION o f Pr em ier O il P LC. Thi s doc ument and the In(ormation disclosed withi n sha ll not be rep roduced in whole or I n p art t o any t hir d par ty any
purpose whatsoever Including conceptual destgn. engineering, manufacturing or construction without the express written permission of P remie r 01 1PLC .
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6.2.2 Packer types
Packers are essential to a great many well completions, whether single or multiple
zone. By physically isolating the casing/tubing annulus from the production zone
they contribute to both well safety and production flow stability. The most common
uses are:
-
. Well protection - prevent formation fluids from entering the annulus
- provide corrosion and abrasion protection
- provide casing and wellhead burst protection
. Production stability - isolate the casing walls and avoid the heading cycle
. Zonal isolation - selective production in single tubing completions or multi-
string
completions with separate tubing for each zone to prevent
cross-zone flow and fluid commingling
- prevent loss of high density fluids to the reservoir during
workover and well-closure operations
. U-tube prevention - prevent annulus injection fluids from affecting tubing
production flow
annulus protection during high pressure injection
operations
Packer Components
The element isolates and seals off the annulus by compression or inflation when
the tool is set and comprises one or more rings of Nitrile rubber or another
elastomer. Teflon or Viton elements are used in H2Sor C02 environments. Various
mechanisms have been developed to extend the life of elements by reducing their
exposure to the high pressures and temperatures that cause degradation.
The slip system is an assemblage of mechanical slips that support the packer
while it is being set and in some cases prevent unplanned reversal of the element
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 57
Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1
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purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written pe011lssion o f Premier O il PLC .
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extrusion process. They are located above and/or below the elements and are
forced into the casing wall to start the setting process.
-
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This document contains CO NF IDE NT IAL and PR OP RI ET ARY I NF ORM AT IO N o f Pr em ier Oil PLC, This document and the information disclosed w ithi n sha ll n ot b e rep ro du ce d i n who le o r i n par t to a ny thi rd par ty any
purpose whatsoever Induding conceptual design. engineering, manufacturing or construction without the express wrinen pel111issionof Premier Oil PlC.
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-
Date 1/3/98
Ref.
Setting and release mechanisms are either mechanical or hydraulic systems that
allow the packer to be set or released as required. Typically they involve either
pipe rotation followed by setting down weight for extrusion, or surface
pressurisation for inflation - or a combination of these. Packers are available for
setting with drill pipe, production tubing, and wireline or coiled tubing.
As illustrated on the next page, packers are classified by the setting mechanism,
permanency in the well and the type of completion.
Prep.by : IESL Section No.
Revision: A
Guidelines to Well Completion Design
RDS Resource - Premier Oil Plc
Page No.: 59
Version: 1
This document co nt ai ns CONF IDENT IAL and PROPRIETARY INFORMATION of P remie r O il P LC. This doc ument and the infannation disclosed within shall not be reproduced i n who le o r i npar t to any thi rd par ty any
purpose whatsoever including conceptual design, engineering, manufacturing or construdkm wi thout t he express writ ten pennission of Premier Oil PLC.
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-
Classification of Packers
I
Retrievable III Permanent I
Permanent -Retrievable
Packer
Classification
I Completion stage I I
Setting/Sealing
Stress state of the
completion string
Type of settingmechanism
Drilling stage
Completion type
Inflatable
element
Date 1/3/98
Ref.
Prep. by : IESL
Compressionof the
SectionNo.
Revision:APage No.: 60
Version: 1
Rota-mechanical set Hydraulic setting
This document contains CONFIDENT IAL and PROPRIETARY INFORMATION of Premier Oil PLC . This documen t and the information disclosed within shall not be reproduced In whole or in part to any thi rd par ty any
purpose whatsoever Induding conceptual design. engineering, manufaduring or constnJdion without the express written permission of Premier Oil PLC.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc
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Packers used in well completion
Pertnanentpackers
As these are designed to remain in the well they can only be removed by milling,
although the tubing can usually be withdrawn from the packer bore. Permanent
packers can be run on wireline, drill pipe or tubing for setting by mechanical
manipulation, or on tubing for setting hydraulically. Some of the advantages of
permanent packers are:
.....
. Reliable sealing even with high pressure differential across the packer or high
temperature
. Accurate depth positioning and fast installation by wireline
. Tubing retrieval without unsetting the packer
The main disadvantage is that the packer cannot be retrieved with the tubing and
can only be removed expensively bymilling.
Retrievable packers
With a setting/unsettingmechanismthat can be eithermechanicalor hydraulic,a
retrievablepackeris frequentlypartof thecompletion.Thereare threecategories:
. Dual slip and cone system below the element
. Single slip and cone held in position by compression or tension
. Single slip and cone system with optional hydraulic hold-down.
Pertnanent - retrievable packers
New models of packer offer the reliability advantages of a permanent packer with
the convenience of a retrievable. Typical is the OTIS Permatrieve packer, which
has three elements that are straddled by an upper and lower slip/cone assembly. It
can be set hydraulically, by rotation, or on wireline and, if a seal unit is used, can
also be run on drill pipe or tubing. When the tubing has been unlatched and pulled
Date 1/3/98 IPrep. by : IESL I Guidelines to WellCompletion Design I SectionNo. IPageNo.: 61
Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1
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out, a J-slot retrieval tool is run to unset the packer by puiling. The Permatrieve
packer is illustrated below.
- PERMATRIEVE DIAGRAM-
Packer setting mechanisms
Weight set - The elements are confined by a cone system that is actuated by
rotation, sometimes in combination with a J-slot. Setting down tubing weight then
extrudes and compresses the elements. Picking up string weight allows the
elements to relax and unseats the packer, although it may be unseated by a high
pressure differential from below. This type of mechanism may not be suitable for
horizontal wells.
-Tension set - This is essentially an inverted weight-set packer that is used where
there is high bottom hole pressure, as in a water injection well.
Rotational set - Rotation of the tubing starts setting the packer, either by releasing
the slips or actuating the cone system to extrude the elements.
Electric wireline set - The packer, with a special adapter kit installed, is run into the
well on electric wireline, which has a depth correlation device such as a casing
collar locator (CCL). At setting depth, a signal transmitted to the adapter kit ignites
a slow burning charge that gradually builds up gas pressure to actuate the
element-compression system. Although this is a fast and accurate installation
system it is difficult to apply in deviated wells and has the disadvantage of setting
the packer separately from installing the tubing.
Hydraulic set - Pressure applied internally to the completion string generates
hydraulic power that actuates the packer setting mechanism. A piston either acts
on the slip and cone system to set the packer and establish the element seal, or
activates a set of upper slips so that pulling on the packer will compress the
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPageNo.: 62
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
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purpose whatsoever including conceptual design. engineering, manufacturing or construClion without the express written permission of Premier Oil PLC.
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elements. In the slip and cone system, the activated cone is locked in position
mechanically. The main techniques for plugging the tubing so that internal
pressure can be applied include:
. Installation of a blanking plug in an appropriate nipple
. An expandable seat activated by dropping a ball, then after packer set, is
sheared out by applied pressure and drops into the well sump
. A differential displacing sub through whose ports the tubing fluid is displaced
prior to setting the packer. When a ball is dropped it seats on an expandable collet
that allows pressure to be generated. Overpressure then moves the collet
downwards, closing the circulation valve and letting the ball drop through.
Stress condition of the string
As the stress condition of the string is affected by well pressure and temperature
variations in these may have significant stress effects on the string.
Classification by completion type
Single zone completion
Annular isolation is often desirable for completions designed to produce from a
single zone, to avoid complications from any increase in casing head pressure at
surface. A packer is used for such isolation, normally being set as close to the
reservoir as possible to minimise the volume of gas trapped underneath.
Multiple completion packers
In producing from multiple zones it is normally necessary to isolate from the
annulus as well as between each zone. While permanent packers may be required
for high pressure or other specific well conditions, retrievable packers are generally
preferred because of the complexity of the completion. Multiple string packers are
available with similar permanency and setting method specifications as single
string packers, although the upper packer may not be wireline settable because of
cable weight limitations. .
Date 1/3/98 IPrep.by: IESL I Guidelines to WellCompletion Design ISectionNo. IPage No.: 63
Ref. I I RDS Resource - Premier Oil PIc IRevision: A IVersion: 1
T his do cu me nt co nt ain s CO NF ID EN TI AL a nd P RO PRI ET AR Y I NF ORM AT IO N of Pr emi er O il P LC . T his do cu me nt and the infonnation disclosed within shall no t be r ep rodu ce d i n whole or in p ar t t o a ny t hir d pa rt y any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written pennission of Premier Oil PLC.
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Multiple string packers must have communication between the tubing above and below
for each string. Some designs have mechanical features such as threaded connections
for tubing make-up to the packer, while others have a seal bore.
-
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 64
Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1This document contains CONFIDENTIAL a nd PROPRIE TA RY INFORMA TION of Premi er OilPLC. This document and the infonnation disclosed within shall not be r eproduced In whole or in p art t o any t hi rd par ty anypurpose whatsoever induding conceptual design, engineering, manufacturing or construction without I he e xp re ss w ri tt en pennission of Premi er Oi l PLC.
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6.2.3 Nipples, mandrels and accessories
Nipples
A nipple is a sub with threaded connections and an internal bore profile that is
precisely configured and machined to accept a mandrel of matching size and
external profile. Nipples are an integral part of the completion and are made up in
the string as it is being run into the well. They perform many important functions
from tubing isolation to carrying later-installed flow regulators, surface controlled
equipment (e.g. SCSSVs) or pressure/temperature sensors. There are two basic
types of nipple:
- . Selective
. Non-selective or "no-go"
Selective nipples have an internal profile that matches a set of locating keys on a
mandrel and can have 5 - 7 selective positions. They are run as part of the
completion string in a sequence matching the locating keys so that they will be at
the correct depths for future mandrel placement.
Selectivity with a single nipple can also be achieved by changing the locking profile
of the running tools, which have a series of removable locking, and sealing
devices. Thus, it is the setting tool outer profile that determines which mandrel sets
in which nipple. With this system, an unlimited number of same-size landing
nipples can be installed in the completion string.
An alternative technique is pre-spaced magnetic selectivity, where different
spacing of magnets in the nipple and mandrel give up to six selection options - with
locking only when the mandrel magnets correspond exactly with the magnetic
rings of the nipple.
Date 1/3/98 Prep. by : IESL Guidelines to Well Completion Design SectionNo. PageNo.: 65
Ref. RDS Resource - Premier Oil PIc Revision: A Version: 1
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purpose whatsoever including conceptual design. eng ineering , manufacturing or const ruct ion without the express wri tt en permission of P remier Oil PLC.
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Non-selective or "no-go" nipples depend on the mandrel OD matching a restriction
in the nipple ID - a larger OD mandrel being excluded but one of smaller OD
passing through without seating. The largest ID nipple is the topmost in the
completion string, the ID of each nipple downwards being progressively smaller.
While the ID-restriction of the nipple may be at the bottom of the profile, it is best
to be at the top to lessen the risk of damage to the polished seal section.
Mandrels
This is a device specifically designed to lock into the internal bore of a nipple and
seal-oft in the sealing section of the ID. The mandrel is run through the tubing to
the correct nipple where it will either seat (non-selective) or its locking pins will be
activated (selective) and is then set into the nipple ID by,jarring upwards. Various
mandrel types are illustrated below.
- MANDREL DIAGRAM -
Accessories
Nipple profiles obstruct production or injection flow because the convergence and
divergence of the nipple system causes severe turbulence, that in turn can lead to
erosion of the tubing and nipple system. Accessories such as flow couplings can be
installed above and below a particular nipple to provide convergence and minimise
abrasion by the flowing fluid. Flow couplings are subs manufactured of harder material
than the tubing and normally have a larger OD to cope with potential erosion. Detailed
size and type specifications for some nipples and components are tabulated below.
Date 1/3/98 IPrep. by: IESLRef.
Guidelines to WellCompletion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision:A
Page No.: 66
Version: 1
This document contains CONF IDENT IAL and PROPRIETARY INFORMATION of Pr em ier O il P LC. Thi s document and the information disclosed within shall not be reproduced in whole or I n pa rt t o any t hir d par ty any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wriUenpenTIlsslon of P remie r Oi l PLC .
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COMPONENT MANUF. TYPE OUTERDIAMETEROFPRODUCTIONTUBING2 3/8" 2 7/8" 31/2" 4" 4 1/2"
1.781 2.250 2.750 3.1250 3.688
BAKER MOD. L 1.812 2.312 2.812 3.250 3.812
1.875 - - 3.312 -
MOD.X 1.375 2.312 2.750 3.312 3.812- - 2.812 -
OTIS 1.500 1.875 2.188 3.125 3.437
SLIDING MOD. R 1.710 2.000 2.312 3.250 3.688
SLEEVE 1.781 2.125 2.562- 2.188 - -
MOD. W 1.875 2.312 2.812 -
MOD.C 1.812 2.250 2.750 3.840
CAMCO 1.937 2.351 2.937 -
MOD. DB - - - 3.312 3.687
Selective 1.781 2.062 2.562 3.125 3.688
No-go 1.728 1.978 2.442 3.072 3.625
BAKER MOD. Selective 1.812 2.250 2.750 3.312 3.750
R No-go 1.760 2.197 2.697 3.242 3.700Selective 1.875 - - - 3.812
No-go 1.822 - - - 3.759
BOTTOM Selective 1.500 1,875 2.188 3.125 3.437
NO GO No-go 1.345 1.716 2.010 2.907 3.162
NIPPLE Selective 1.710 2.000 2.312 3.250 3.688
No-go 1.560 1.821 2.131 3.088 3.456
OTIS MOD. Selective 1.781 2.125 2.562
RN No-go 1.640 1.937 2.329 - -
Selective - 2.188 - - - ,
No-go- 2.010 -
Selective 1.875 2.312 2.750 3.312 3.812
MOD. No-go 1.791 2.205 2.635 3.125 3.725
XN Selective - - 2.875 - -
No-go - - 2.760 - -1.781 2.062 2.562 3.125 3.688
BAKER MOD. F 1.812 2.250 2.750 3.250 3.750
1.375 2.312 2.812 3.312 3.812
1.375 2.312 2.750 3.312 3.812
MOD. X 1.905 2.380 2.812 - -
- - 2.875 - -
OTIS 1.500 1.875 2.188 3.125 3.437
TOP NO - GO MOD.R 1.710 2.000 2.312 3.250 3.688
SELECTIVE 1.781 2.125 2.562 - 3.812
1.562 1.875 2.125 3.187 3.500
1.312 2.000 2.250 3.312 3.625
1.765 2.062 2.312 3.687
CAMCO MOD. 0 2.125 2.437 3.7502.188 2.562 - 3.812
- 2.250 2.703 - 3.875
MOD. ERA-1 1.781 2.062 2.562 3.125 3.688
SELECTIVE BAKER 1.812 2.250 2.750 3.250 3.750
RECEPTACLE MOD. ELA-1 1.875 2.312 2.812 3.312 3.812
Date 1/3/98 IPrep.by: IESL T Guidelines to Well Completion Design I SectionNo. IPage No.: 67
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
This document contains CONFIDENTIAL and PROPRIETARY INFORMATION ofPremierOilPLC.Thisdocumentandthe infonnationdisclosedwithinshallnotbe reproducedin wholeorin partto anythird party any
purpose whatsoever induding conceptual design. engineering, manufacturing or construction without the express written permission of Premier Oil PLC.
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...
-- ,,--~-
CAMCO MOD L.J 1.8121.875
2.250
2.312
COMPONENT ( MANUF. TYPE OUTERDIAMETEROFPRODUCTIONTUBING2 3/8" 27/8" 3 1/2" 4" 4 1/2"
2.562
MOD.SL - - 2.750 -BAKER - - 2.812
MOD.VL - 3.812MODFVL 1.875 2.188 2.560 3.812MODFVL - 2.312 -
MOD. TRB-8-FSR 1.375 2.312 2.812 -
TUBING CAMCO MOD. TRDP-1A-SSA 1.375 2.312 2.812 3.812
MOUNTED MOD. TRDP-2A-SSA 1.375 2.312 3.812
SAFETY MOD.QLP 1.375 2.312 2.75 3.812
VALVE MOD. QLP 1.375 2.312 2.812 - 3.812
MOD. DL 1.710 2.313 2.750 3.813
1.875 - - -
MOD. FMX 1.875 2.313 2.750 2.813
Flapper - - 2.813 -OTIS MOD. FMR 1.710 2.125 2.562 3.688
Flapper 1.781 2.188 - -
MOD. BMX 1.875 2.313 2.750 3.813Ball - - 2.813 - -MOD. BMR 1.710 2.188 2.562 3.688Ball 1.781 - - -
NIPPLE 2.562 3.125 3.688DHSV 1.262 1.625 2.000
MOD. NIPPLE - - 2.750 3.313 3.750BFX DHSV - - 1.262 1.625 2.000
NIPPLE 2.812 3.812
DHSV 1.625 2.312
BAKER NIPPLE 1.718 2.188 2.562 3.688
WIRELlNE MOD. DHSV 0.650 0.935 1.265 1.970
SAFETY BFV NIPPLE 1.875 2.312 2.812 3.812
VALVES BFVH DHSV 0.807 1.125 1.560 2.122
NIPPLE 1.718 2.188 2.562 3.688
MOD. DHSV 0.650 0.935 1.265 1.970
BFVE NIPPLE 1.875 2.312 2.812 3.812
BFVHE DHSV 0.807 1.125 1.560 - 2.122NIPPLE 3.688
MOD. DHSV - - - -WRDP-1 NIPPLE - - - 3.812
DHSV 2.125CAMCO MOD. NIPPLE 1.875 2.312 2.812 3.812
B7 DHSV 0.734 1.125 1.375 2.125
NIPPLE 1.875 2.312 2.750MOD. DHSV 0.734 1.125 1.375 -
WRDP-1 NIPPLE - - 2.812 -DHSV - - 1.562NIPPLE 1.710 2.125 2.562 3.125 3.437
MOD. DHSV 0.620 0.810 1.000 1.500 1.625
Date 1/3/98 IPrep.by : IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 68Ret. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
This do cument c ont ains CONF IDENT IAL and PROPRIETARY INFORMAT ION o f P remie r O il PLC. This d ocument and the infonnation disclosed with in shall not b e reproduced in who le or in part to any thi rd par ty anypurpose whatsoever Including conceptual design, engineering, manufacturing or constnJdion without the express wrihen pennission of Premier Oil PLC.
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Date 1/3/98
Ref.
Prep. by : IESL Guidelines to Well Completion Design
RDS Resource - Premier Oil Pic
SectionNo.
Revision:APage No.: 69
Version: 1
This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premi er Oil PLC. Thi s document and the information disdosed within shall not be reproduced in whole or inpart to any thi rd par ty anypurpose whatsoever Indueling conceptual design, engineering, manufacturing or c:onstnJdton without the express written permission of Premier Oil PLC .
OK NIPPLE 1.875 2.188 2.750 3.313 3.688
DHSV 0.620 0.810 1.380 1.750 1.875
NIPPLE - 2.313 2.813 3.812
DHSV - 1.000 1.380 2.000
NIPPLE 1.875 2.125 2.562 3.688
OTIS MOD. DHSV 0.750 0.810 1.000 1.870
FE/FXE NIPPLE 2.188 2.750 3.813
DHSV - 0.810 1.500 2.120
NIPPLE - 2.313 2.813 - -
DHSV 1.120 1.500 -
NIPPLE 1.875 2.125 2.562 3.688
MOD. DHSV 0.620 0.310 1.000 1.870BE/BXE NIPPLE 2.188 2.750 3.813
DHSV - 0.810 1.380 2.000NIPPLE - 2.313 2.813 -
DHSV 1.000 1.380 -
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6.3 Special equipment
After the packer has been set and the completion string is run into the hole it has
to seal - and optionally latch - into the packer bore. Polished bore receptacles
provide a downhole sealing surface into which penetrators with a seal-stack can be
stabbed. When thermal expansion and contraction during production or injection
operations cause the seal-stack to slide along the polished bore it still maintains an
effective seal.
Seals that are arranged on the outside of the tubing seal must be specified on the
basis of:
. Geometrical design
. Chemical composition
. Length of system
Geometrical Design
The most common type of seal assembly is the chevron seal that comprises two
stacks of V-section rings mounted in opposing directions. Differential pressure
across the assembly deflects the chevrons outwards to fill the gap between seal
bore and polished bore receptacle. Standard O-rings can be used in lower
pressure differential environments.
Chemical Composition
The seal composition specified must be resistant to any H2S, C02 or other
corrosive or aggressive materials in the wellbore. Seals are usually spaced along
the length of the seal tube and separated by metal and/or Teflon back-up rings.
See Section 4.4.2 for detailed seal selection criteria.
Length of seal system
Once the seal assembly is located within the polished bore receptacle it will move
in response to expansion or contraction of the tubing, so both must be of adequate
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 70
Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1This document contains CONF IDENT IAL and PROPRIETARY INFORMATION of Pr em ier O il P LC. Thi s doc ument and the information disclosed within shall not be reproduced in whole or Inpar t to any thi rd par ty any
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length to provide effective sealing under all conditions. In some circumstances a
longer seal assembly may be needed to reduce the risk of leakage.
Seal bore specification
The 10and length of the seal bore is highly dependent on both the type of packer
and the casing size in which it will be set. However, the seal bore should be
maximised to cause the least possible reduction in flow. A seal bore extension is
often coupled to the polished bore receptacle to give a longer seal area that
reduces the possibility of seal failure.
Seal Assembly specification
Tubing assemblies can be supplied with either:
--
. Seal system only (locator tubing seal assemblies)
. Seal system with mechanical latch above to engage the upper bore of the
packer
Date 1/3/98 IPrep.by: IESL T Guidelines to Well Completion Design ISectionNo. IPage No.: 71Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1This document con ta ins CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the infonnation disclosed within shall not be reproduced in whole or inpar t t o any t hi rd p ar ty any
purpose whatsoever including conceptual design, engineering, manufacturing or ronstruction without t he ex pr ess wr it ten p ermi ssi on o f Pr emi er O il P LC ,
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7 COMPLETION DESIGN FOR SPECIAL APPLICATIONS
7.1 Artificial Lift
7.1.1 Electric Submersible Pump completions
Driven by a downhole electric motor, these multi-stage centrifugal pumps can
greatly improve production rates in wells, which have low bottomhole pressure. An
ESP completion can be packer-based or packerless and will differ little from those
described earlier. The pump assembly comprises:
-
Motor
This is a squirrel~cage AC induction electric motor that is filled with a specialdielectric oil to prevent overheating and is additionally cooled by the fluid flowing
round it into the pump. Although power output was traditionally restricted by casing
size and stator length, recent developments have seen tandem-mounted J1lotors
that in some casing sizes give more than 100% increased output.
Pump
Because of the wide range of capacities required of these multi-stage pumps, a
variety of impeller designs are available for each pump size. This allows selectionof a suitably efficient design for the particular volume requirement.
Protector
A protector or seal that is located between the motor and pump, prevents well
fluids from entering the motor. It also allows thermal expansion and contraction of
the motor oil under different motor loads. Many protectors are tandem (Le. in
series) and have seal sections that equalise the motor internal pressure with
wellbore pressure.
Power Cable
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 73
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
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purpose whatsoever including conceptual design. engineering, manufacturing or oonstruction without the express written permission of Premier Oil PLC.
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An ESP is powered by a flat or round 3-conductor cable that is sized for the motor
requirement. The cable has well-insulated copper conductors, is metal armoured,
can tolerate high temperature and pressure and is oil- and water-resistant. As the
ESP is being installed, the cable is clamped onto the production tubing at 30 ft
intervals. Special cables are available for particularly corrosive environments and
high pressures and temperatures.
Gas separation
Wells producing with a high GOR may require a gas separator instead of the
standard intake section of the pump. Rotary separators are among the various
types available that can more than double the production rate in a well. In packer
completions, the separated gas passes through a vent valve into the annulus from
which it is vented at surface through the casing valves. However, this exposes the
cable to the produced gas and the risk of failure due to decompression.
Controls, switchboard and power supply
ESP controls can be of widely differing levels of sophistication. Although the most
basic type has no more than a button to make or break the circuit and an
over/under-load protector, it works sufficiently well over the range 440 to 2300
volts. More advanced controls may have a switchboard with recording ammeters,
signal lights and timers for intermittent pump operation. Where possible, land
operations draw power from the national supply, although remote locations may
require an on-site power generation facility
Date 1/3/98 IPrep. by : IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 74-
Ref. I I RDS Resource - Premier Oil PIc T Revision: A ., Version: 1
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purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written p ermi ssi on of P rem ie r O il P LC.
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Transformers
Wellhead
MotorController
Junction00x
Checkvalve
Powercable
cableband
Flatcable
Tubing
CentrifugalPump
SealSection
ESP completion design
Date 1/3/98 IPrep.by: IESL I Guidelines to WellCompletion Design ISectionNo. IPage No.: 76Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1Thisd oc umen t c on tai ns CONF IDENT IAL an d PROPRIETARY INFORMAT ION o f P rem ie r O il P LC. Thi s d oc umen t and the information disclosed within shall not be reproduced in whole or in part to any third part y any
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-
Calculating the energy requirements for the pump is the first step in designing an
ESP completion. After selecting a suitable model (usually on a per stage basis)
then the motor, seal, cable and surface facilities can be sized to integrate with the
rest of the system.
Total Dynamic Head (TDH)
This is the energy that the pump must impart to the fluid to lift it to surface, taking
account of friction losses in the tubing and the required wellhead pressure.
TOH = Net Lift + Friction Losses + Wellhead Tubing Pressure
Pump selection starts by determining the largest 00 unit that will fit into the casing
and has the required production rate within its operating range. In general, the
largest diameters are generally preferred because of their advantages:
. Larger diameters are more efficient
. Larger units are normally less expensive
. Larger pumps run at lower temperatures because of higher fluid velocity
From the largest 00 pump series identified as being suitable must be selected the
model whose maximum efficiency is at a rate close to the required production rate.
Illustrated on the next page is a typical manufacturer's pump performance graph
showing the efficiency, horsepower and head capacity versus the flow rate. From
this can be obtained the head capacity at the selected flow rate, which with the
TOH, allows the number of stages needed to be calculated using the following
formula:
Number of stages required = TOH I Head generated per stage
The power-per-stage value is now established from the performance graph so that
the brake horsepower necessary to power the pump can be calculated:
Date 1/3/98 I Prep. by: IESL
Ref.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision: A
Page No.: 77
Version: 1
This doc umen t c ont ains CONF IDENT IAL an d PROPRIETARY INFORMAT ION of P rem ie r O il P LC. Thi s document and the information disclosed wit hin shall not be reproduced in whole or in part to any t hird party any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wr iUen pe rm is sio n o f Pr emi er O il P LC .
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BHP = BHP/Stage x No. of Stages x Specific Gravity of fluid to be
pumped
The next step is the choice of a seal section - usually dependant on the pump size, as
each manufacturer will have a seal corresponding to the pump 0.0. Because the seal
dissipates power in relation to the total dynamic head, the value of the pressure drop in
the seal can be read from a table supplied by the pump manufacturer.
Having calculated the power requirements for the motor and seal, the motor itself can
now be selected. Subject to the same diameter limitations as the pump, a motor is
chosen whose rating is slightly higher than the total power requirements to avoid
operational overloading that would shorten its run-life. Most motors are available with
Date 1/3/98
Ref.
Prep. by : IESL Guidelines to Well Completion Design
RDS Resource - Premier Oil Pic
SectionNo.
Revision: A
Page No.: 78
Version: 1
ThiS document contains CONFIDENTIA L a nd PROPRIETARY INFORMATI ON of P rem ier Oi l PLC. This document and the Information disclosed within shall not be reproduced in whole or inpart to any thi rd par ty anypurpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written permission of Premier OilPLC.
HEAD I I I I I IBRAKE PUMP
INI I I I I I
HP EFF
FEET OPERAl1NG RANGE %
35 70
HE CA TV
30 60
25 50
PUMP ONLY
EFRCIENCY
20 40
i
15 .75 30
10 .5 20
MOTOR LOAD BRAKE
HORSEPOWER- .- - . no - - - .- - - -- .. - -
5 .25 10
500 1000 1500 2000 2500 3000 3500
BARRELS PERDAY
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higher voltage/lower current and lower voltage/higher current options. The decision
between them is purely economic as high voltage requires a more expensive controller
but cheaper cable, with the opposite requirement for the lower voltage option.
The main factors in cable selection are cost - proportional to size - and voltage
drops caused by resistance losses which are inversely proportional to size. Other
factors are the amperage and the space between tubing collars and casing. The
cable voltage drop (from tables), modified for temperature, is then added to the
motor voltage to give the total voltage needed at surface. Choosing the surface
controls completes the pump selection operation.
-In more demanding environments such as high GOR, sour gas or very viscous
crude's, additional factors have to be considered in determining the optimum size
and type of equipment for the life of the well. These factors will include the cable
jacket and insulation and the erosion characteristics of the produced fluids.
Date 1/3/98 IPrep.by: IESL I Guidelines to WellCompletion Design ISectionNo. IPage No.: 79
Ref. I I RDS Resource - Premier Oil Pic IRevision: A IVersion: 1
This document co nt ai ns CO NF IDENT IA L and PRO PRI ET ARY I NF ORMA TI ON of Pr em ier O il P LC. T hi s doc um ent and the information disclosed withinshal l not be reproduced in whole or inpart t o any t hir d pa rt y any
purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express \Wine" pennisslon of Premier Oil PLC.
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7.1.2 Gas lift completions
Of the many forms of artificial lift used in modern production operations, gas lift
most closely resembles the natural process. It is defined as a system of lifting
liquids from a well bore by adding relatively high pressure gas to the downhole
fluid column. This supplementing of the reservoir energy may be done by
continuously injecting high pressure gas at a relatively low rate (continuous flow) or
by the short dur;3tion injection of a larger gas volume underneath a slug of liquid
that it will raise to the surface intact (intermittent flow).
-
Continuous flow gas lift is best suited for high fluid level wells that do not have
sufficient gas pressure and/or volume to flow naturally. Intermittent flow gas lift is
for low-rate wells with low bottomhole pressure. Injected gas lifts production liquids
to the surface by one or more of the following processes:
. Reduction of fluid gradients
. Expansion of injected gas
. Liquid displacement by compressed gas
Gas lift is suitable for almost every situation requiring artificial lift. It will artificially
lift an oil well to depletion regardless of the ultimate producing rate or water cut;
kick-off wells that will flow naturally; backflow. water injection wells; or unloads
water from gas wells. Some of its advantages and limitations are:
. Initial equipment costs are usually less than for other forms of artificial lift
. Minimummaintenancecosts
. Design flexibility through the well life - from near-surface lifting initially, to near-
total-depth lifting at depletion
. Not affected by wellbore deviation
. Long term reliable performance
. Gas availability may be difficult
. Wide well spacing might restrict use of a central gas source
Date 1/3/98 IPrep.by: IESL I Guidelines to WellCompletion Design ISectionNo. IPage No.: 80
Ref. I I RDS Resource - Premier Oil PIc IRevision: A IVersion: 1
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purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express wrihen permi ss ion o f Premier Oil PLC .
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. Not entirely suitable for multilayer production
. Highly corrosive gas can damage the completion string and components
Types of installation
There are three main types of gas lift installation -Open, Semi-closed and Closed.
Open Installation has open communication between tubing and casing so is
restricted to continuous flow in good wells. Not recommended for modern
completions.
-
Semiclosed Installations use a packer to isolate the annulus. This type of
installation is suitable for both continuous and intermittent gas lift and has several
advantages over open installations. After the well has been unloaded liquid cannot
return to the annulus, while fluid movement through valves is restricted to the kick-
off stage and to the operating valve during production.
Closed installations are similar to semi-closed installations but with a standing
valve on the tubing string to prevent the gas injection pressure from acting on the
formation. Most gas lift applications benefit from having a standing valve.
Gas lift valves
The standard gas lift valve is a special, unbalanced type of motor valve that is
actuated by external pressure. Depending on how it is placed in the tubing string,
the valve can be operated either by casing pressure or tubing liquid pressure. Gas
lift valves are generally classified by the type of service and loading:
Service-type · Continuous flow
· Intermittent flow
- fixed orifice
- variable orifice
- minimum tubing-pressure control
- maximum tubing-pressure control
Loading-type. Gas-charged (bellows, piston or rubber sleeve chamber)
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....---
· Mechanically loaded (spring, piston loaded)
· Combination (mechanically and gas charged)
· Liquid-charged diaphragm
The two basic types of gas lift valves differ only in their individual retrieval features:
. Pressure loaded (including spring-loaded)
. Mechanically operated
All makes of pressure-operated valves use the same basic operating principle and,
with one exception, can be used in either continuous or intermittent flow after only
minor modification. The exception is the Harold Brown (McEvoy) type MD "specific
gravity", automatic continuous flow valve. Although some mechanically operated
valves are for continuous flow only, many can be used for either type of operation.
All types of gas lift are reviewed whether or not they are recommended for use.
There is little difference in quality between the various commonly used valves
currently available. Conventional valves are all fabricated from Monel or stainless
steel, while all bellows come from the same manufacturing source. The bellows-
valves all have a tungsten carbide ball that seats on Monel, stainless steel or
nylon, although Guiberson use a carbide ball-seat. Thus, the primary valve
selection factor is determining the correct valve.,typefor the application.
Basic operating principle
A gas-lift valve comprises a sealed pre-load pressure system acting on a flexible
diaphragm or bellows that controls a sealable port, typically opening to the tubing,
while apertures in the valve body allow annulus pressure to act on the bellows
against the pre-load pressure (see diagram on next page). The pre-load pressure
is generated either mechanically by a calibrated spring, hydraulically with pre-
charged fluid or by a combination of both. Because valve operation is controlled by
the pressure-source acting on the usually larger bellows area and not by the
pressure applied to the smaller area of the valve seat, it is classified as either
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-
annulus-controlled (as here) or tubing-controlled. Thus, excess tubing pressure on
the seat opens the valve and allows annulus gas to flow into the tubing until
declining pressure recloses the port.
For different applications, the size and hence hydraulic area of both bellows and
valve seat can be varied considerably, as can the pre-load pressure. Thus, the
larger the valve seat for a given bellows area, the greater the reaction to tubing
pressure and a lower pressure requirement in the annulus. Some continuous-flow
gas lift valves maximise tubing sensitivity with a large valve seat area while
restricting annulus gas inflow either with a tapered valve stem or small inflow ports.
By contrast, larger inflow ports may be required in intermittent-flow gas lift valves
to allow an instant large gas volume inflow to the tubing from the constant
pressure annulus - particularly necessary for automatic function whenever a
specific liquid head has built up in the tubing. This requires the valve to be fast
acting. As excessive valve spread (difference between the opening and closing
pressure - see below) can allow through unnecessarily large gas volumes, some of
the tubing pressure effect must be balanced in the valve design.
Gas lift valve types
Gas-charged bellows intermittent valve
The bellows used in conventional gas lift valves is of 3-ply Monel, each ply being
0.005 inch to give 0.015 inch total wall thickness. Three types of bellows protection
are in use:
. Liquid charge to prevent collapse with high differential pressure (USI and
Guiberson)
. Teflon reinforcing rings (Harold Brown)
· Bellows convolutes pre-formed for mutual support by subjecting them to 3000psi differential pressure (Camco, Macco -with valve travel stop)
Date 1/3/98 I Prep. by: IESLRef.
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RDS Resource - Premier Oil Pic
SectionNo.
Revision: A
Page No.: 83
Version: 1
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The Macco gas-charged bellows design is used only in casing-pressure operated
installations. Both the Guiberson and Harold Brown valves have a field inspection
facility.
As a spring provides the loading force in the Macco valve for fluid weight
applications there is no charge pressure. The spring-loaded valve, which
supersedes their previous gas-charged model, eliminates the need for a
temperature compensation in the installation design. The USI fluid-operated valve
is a conversion of their Balance Pressure Valve that has tubing rather than casing
pressure acting on the bellows area. This allows the casing pressure to be
completely balanced so that valve operation is controlled only by tubing pressure
build-up.
Spring-loaded differential intermittent valve
In all models casing pressure acts on a piston having the same hydraulic area as
the stem on which tubing pressure acts. The spring load holds the valve open until
it is overcome by increasing differential pressure across the small inlet choke. On
all other types of valve the loading force tends to hold the valve closed until the
differential between casing and tubing pressure becomes less than the spring
setting and the valve opens.
Combination spring and gas-charged bellows intermittent valve
A combination of spring and gas-charged bellows provides the loading force in this
type of valve. Although the spring setting is usually about 75 psi this can vary
between different valve series, so it is important that the user checks and records it
precisely. The valve pressure can be field-adjusted with the calibrated spring and
has a reduced temperature factor because the spring provides part of the loading
force. Although the spring will keep the valve closed in case of bellows failure, it
cannot be opened by casing pressure.
Continuous flow valves
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All the preceding intermittent-flow valves can be modified for use as continuous
flow valves.
Operating characteristics
Area factors
The bellows-type valve has three hydraulic areas on which pressure can act - the
bellows (Ab).the stem (As)and the port (Ap).Although various manufacturers use
different conventions for their operating equations. the following has been adopted
Since most valves have equal stem and port areas it is assumed that As = Ap
unless otherwise noted, allowing the area ratios of a valve to be characterised by a
single factor, since by definition:
The port factors for different types of valve are calculated from the dimensions
quoted in manufacturers' catalogues.
Spring tension
Some bellows type valves are equipped with a spring whose spring tension S is
expressed in pounds per square inch of the area (Ab - Ap).Manufacturercatalogues list the standard springs available for their various valve types.
Nominal setting pressure
Date 1/3/98 I Prep. by : IESLRef.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision: A
Page No.: 85
Version: 1
This document contains CONFIDENTIA L a nd PROPRIETARY INFORMATION of P rem ier Oi l Pl C. This do cum ent and the information disclosed within sha ll not be reproduced in wh ole or In p art to any thi rd party anypurpose whatsoever Including conceptual design. engineering, manufacturing or construction without the express written permission o f Premier Oil PlC.
for convenience:
Bellows factor: Fb = Abl (Ab - Ap)
Port factor: Fp = Api (Ab - Ap)
Stem factor: Fs = AsI (Ab - Ap)
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A bellows valve is usually charged with nitrogen for workshop testing, but because
the actual bellows pressure cannot be calibrated without being affected, this must
be done relative to an external Nominal Setting Pressure.
The Nominal Setting Pressure (Pn)is the external pressure at which the
valve opens with atmospheric pressure under the valve stem (P,= 0) at
60°F.
Back pressure effect
-
The back pressure effect is the difference between the normal setting
pressure Pn and the pressure Po at which the valve opens if the
pressure under the stem is P, instead of atmospheric.
An increase or decrease in pressure under the stem is therefore only partly
reflected in the pressure required to open the valve. The factor Fp is frequently
referred to as the "back pressure factor" although it is by definition equal to the port
factor. Thus, the opening pressure of a Garrett OCF type valve decreases by 75
psi when the back pressure is increased from zero to 450 psig.
Valve spread
The valve spread is the difference between the injection pressure
required to open the valve and the injection pressure at which it closes
(PiC)'
The pressure under the stem is not zero under downhole operating conditions, so
that the valve spread depends not only on the valve characteristics (Fp,Fband Pn)
but also on the flowstring pressure and temperature.
Since the gas column gradient can be assumed to be the same for Pioand Pic,the
valve spread is often defined as the difference in surface injection pressure on
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opening and closing the valve. This determines to a large extent the amount of gas
injected per cycle during intermittent gas lift operations.
Gas lift valve classification
The following classification of gas lift valves is based on their main operating
characteristics. It depends on the different possible combinations of the injection
pressure Pi and/or the flowstring pressure Pf that can act on the Ap and (Ab- Ap)
areas in the open and closed positions. A similar distinction can be made for
retrievable, spring loaded and casing flow type gas lift valves.
Pressure Operated Valves
The opening and closing characteristics of this group of valves are governed
primarily by the injection pressure since this acts on the (Ab - Ap) area in both open
and closed positions.>
Valve opening in this group is also partly governed by the flowstring pressure,
which acts under the stem in the closed position. Whether pressure (Pi or Pf) acts
on the stem in the open position depends on where the gas flow is being
controlled.
a) In Continuous Flow Valves or Constant Flow Valves, the gas is controlled by
nozzles upstream from the stem chamber so that flowstring pressure acts on
the stem in the open position. The closing characteristic of this type of valve is
partly dependent on the fluid back pressure.
b) In Intermittent Flow Valves the gas is controlled downstream from the stem
chamber so that the valve closure is independent of flowstring pressure. The
same principles apply to Large Port Valves that have a sealed chamber and abore-hole through the thick part of the stem.
Balanced Pressure Operated Valves
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Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
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...
Because of the construction of the bellows sealed chamber, injection pressure acts
on the stem as well as the bellows in both open and closed positions - flowstring
back pressure has no influence on the way it operates. This also applies to valves,
which have a resilient element. Opening and closure in this group of valves is
wholly governed by gas injection pressure.
Fluid Operated Valves
The opening and closing characteristics of this group of valves are governed
mainly by fluid back pressure as this acts on the area (Ab - Ap) in both open and
closed positions.
a) Conventional Fluid Operated Valves are standard intermittent pressure
operated valves in which the direction of gas flow has been reversed. The
injection pressure thus acts on the stem in the closed position with the opening
characteristic partly dependent on Pi.
b) Intermittent Fluid Operated Valves. Because injection pressure acts on the
stem in the open position its closing characteristic is partly dependent on Pt.
Partly Balanced valves also belong to this group, the name referring to the
influence that injection pressure can also have on the opening characteristic
where the port area is smaller than the stem area.
c) Balanced Fluid Operated Valves. Since the flowstring pressure acts on the
stem as well as the bellows in both open and closed positions, the operating
characteristics are wholly governed by flowstring pressure and independent of
injection pressure. While the opening characteristic can be made dependent on
injection pressure if the port size is smaller than standard, the classification is
unchanged because the closing characteristic is not affected, unlike the group
above.
Differential Valves
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RDS Resource - Premier Oil Pic
SectionNo.
Revision: A
Page No.: 88
Version: 1
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p ur pose wha ts oe ve r i nc lu di ng c on ce pt ua l de si gn , e ngi ne eri ng, ma nuf ac tur in g o r c on st ruc ti on wi tho ut t he e xp re ss wr it te n p en ni ssi on of Premi er Oi l PLC.
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'\a) Spring Type. Spring tension keeps the valve open until overcome by the
pressure differential created by gas flow through nozzles that are upstream
from the stem chamber. Consequently, operating characteristics are
independent of the injection and flowstring pressure values.
.....
b) Bellows Type. The dome chamber has two check valves working in opposite
directions, on which two small springs can be set for the pressure differential
required to open them. This allows dome pressure to be varied without pulling
the valve by increasing or decreasing the injection pressure to a fixed
differential above or below the dome pressure. Thus, valve response to the
combination of injection and flowstring pressure can be changed by
manipulating the surface injection pressure. When set, opening and closure
depend on the pressure differential across the valve
Gas lift mandrels
Also referred to as side pocket mandrels, they are the housing in which the gas lift
valves are installed. The mandrels are installed in the tubing string nipples when
running in the completion, but if artificial lift is not required initially, the valves can
be run in later on wireline. Mandrels are often used to carrY valves for such other
functions as chemical or waterflood injection and fluid circulation.
7.1.3 Coiled Tubing completions
Coiled tubing (CT) is one of the newer technologies available, but so far has been
used only occasionally in completion applications for both new and existing wells. It
was first used to overcome water loading in gas wells by installing a CT string
inside the production tubing to reduce the flow area. This increased the gas
velocity to a level at which it carried the water to surface, so avoiding build-up of a
water column. Also known as a velocity string, this successful technique has led
the way into other more demanding completion applications. Still awaiting wide
acceptance, this type of completion has the following advantages and limitations:
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Advantages
. Lower cost for certain applications
. Rapid installation, reducing rig time and logistics
. Allows fast and safe live well operations without risking reservoir integrity
through killing the well
. Few connections give faster deployment and reduced risk of tubing leaks
. Compatible with artificial lift methods and equipment
Limitations
-
Requires operators with specialised skills
Equipment costs in most countries are higher than conventional jointed
tubing units
Maximum 00 3.5", while string length and metallurgy also to be
considered
. Longevity and field performance of CT completion equipment yet to be
established
.
.
.
. Not yet suitable for highly corrosive conditions requiring CRA materials
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Artificial lift completions - ESP and gas lift - are the most common among the
following CT completion applications that have been established:
Production strings. Primary production strings
· Velocity strings
· Electric submersible pumps
Gas lift · Single point
· Multiple external
· Multiple internal (spoolable)
Wellbore isolation. Production liner
Sand control · Gravel pack
- Injectionstrings · Gasandwaterinjection
Primary production or injection strings
These types of completion are still infrequent, but the ID of the CT string limits
production rates to around 10,000 SOPD.
Advantages · Quick to run, lower cost
· Feasibility proven with main technical difficulties overcome· Live well completion possible
Disadvantages · Equipment transportation and logistics can be complex
· Cost of CT units still high in some geographical areas
· Integrity of mechanical connections can be a problem
· Metallurgy not yet developed for highly corrosive
conditions
Velocity strings
Used to modify the hydraulic characteristics of a completion to reinstate or
increase production and remove water from the wellbore. Mainly used in gas wells,
Date 1/3/98 IPrep. by: IESLRef.
Guidelines to Well Completion Design
RDS Resource - Premier OilPic
SectionNo.
Revision:APage No.: 91
Version: 1
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a velocity string is most effective where a steady reservoir decline is followed by
either a sudden increase in produced liquids, or a sudden halt in production.
,
Advantages
threaded,
Disadvantages ·
and
. Increased production due to flow area reduction
. Minimises coning and fingering in gas wells to prevent
water-out and increase recovery of reserves
. Live well intervention without workover equipment and kill
avoids stopping production from low pressure reservoirs
. Faster installation than changing to smaller size
conventional tubing
. Switchable flow options through CT and annulus may allow
a staged approach to depleting the reservoir
. CT wellhead hangers and related equipment available for
various conditions and configurations from simple
to fully flanged high pressure for sour service
.
Multi-diameter CT string requires specialised equipment
procedures
Need additional equipment and procedures as simplest CT
velocity strings disable the safety valve and master valve
Equipment requirements
Surface . Pressure control equipment besides CT strippers and
BOPs
. Running equipment to facilitate handling and installation of
completion tools and components
. Wellhead equipment that will be integrated with the
permanent wellhead
Downhole tools. Running tools installed on the completion
. Flow control equipment, nipples and related components
Date 1/3/98 Prep. by: IESL
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RDS Resource - Premier Oil PIcSectionNo.
Revision:A
Page No.: 92
Version: 1
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· Packers and anchor tools for isolating or anchoring the CT
completion
-
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Electric submersible pumps (ESP)
CT provides an ideal ESP-conveyance method and production conduit. While the
same factors apply as in a conventional system - tensile strength, load weights,
shut-in loads etc - the maximum ESP motor torque must also be considered.
Advantages · Less time to run in and retrieve ESPs
· Costs may be lower
Disadvantages. Relatively smalllD may increase friction pressure and back
pressure
· Insufficient data to compare life expectancy of jointed pipe
and CT
- Gas lift production
The introduction of larger diameter CT has broadened the utility and applications
for gas lift coiled completions.
Single point injection
. Straight forward CT completion arrangement with the configuration similar to a
velocity string. Either flow path can be used for production.
Multi-point external valves
Usually assembled with clamp-on gas lift mandrels, these are compatible with
annular or tubing production flow paths. The installation generally uses a split
housing to support the gas lift assembly which is completed by drilling a hole in the
CT. Some form of "work window" is necessary for fitting the gas lift valves below
the CT injector head and pressure control equipment..
Advantages · Quick and economical installation with minimum equipment
Disadvantages · External valves not wireline retrievable so whole completion
must be retrieved for valve replacement or servicing
Date 1/3/98 I Prep. by : IESL [Ref.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc~ Section No.
Revision: AJPage No.: 94
Version: 1
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. Valvescannotbeblankedto allowpumpingof treatment
fluids down the CT string
. The gas lift valves and housing may impinge on existing
restrictions in the completion
Multi-point internal valves (Spoolable)
The introduction of larger diameter CT (2 - 3.5" 00) has increased the feasibility of
using internal gas lift valves that are available in several different designs. Once
the drawbacks of multi-point external valves have been overcome, CT gas lift
completions should offer the same advantages as a conventional gas lift system.
-Advantages. Wirelineretrievablevalvesthat can be blanked-offo allow
servicing or wellbore treatments without retrieving the
completion
. Completion entirely spoolable through the CT injector head
and pressure control equipment, saving time and increasing
simplicity
Limitations · Full downhole safety facilities must be provided
7.2 Completion design in wells with sanding problems
In a reservoir prone to producing solids it is essential to try and prevent the
particulate matter entering the production path where it can severely erode tubing
walls and damage wellhead equipment. Resolving the problem in a sandstone
reservoir is a time-consuming and expensive process that should be started at the
earliest possible stage in the life of the field. The present economic climate makes
it even more important that the problem is quickly identified so that cost-effective
measures can be implemented to optimise the productive capacity of the reservoir.
Methods of controlling sand invasion include selective perforation, gravel packing
and slotted liners and screens.
7.2.1 Sand production prediction
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Sand production is a rather complex mechanism that is strongly influenced by the
field stresses and production strategy. Because the methodology and equipment
for identifying the sanding potential of a particular reservoir is still considered more
art than science, only simplified models and local expertise are available to
address the problem. Few theoretical models and empirical techniques have been
developed over the years.
-
The sequential flow test is one of the older but more useful techniques because it
exposes the well to realistic production conditions. Initially used as a prediction tool
it is now mainly used to calibrate the estimates made by the analytical models.
However, it is of limited value because it cannot reflect the changes in field stress
during reservoir depletion.
The combined modulus technique, developed by Mobil in the 70s, was applied
successfully in the US Gulf Coast. Density and sonic logs were used to compute
the elastic modulus of the rock and establish a threshold value of 3 x 106Psi above
which a formation was unlikely to produce sand.
The Mechanical Properties Log (MECPRO) was developed by Schlumberger to
predict the maximum allowable drawdown pressure on the rock before the onset of
sand production. As the model worked better for hydraulic fracturing than for
predicting sand production it was of limited application, but has since been further
developed into ROCPRO and, most recently, IMPACT. Unfortunately, both these
models rely on unrealistic assumptions that are not representative of actual field
conditions. Because IMPACT can use many of the existing models such as Bratli &
Risnes and Coates & Denoo, it could be useful where they can predict sand
production onset with any certainty.
Morita's Model and the work by Kessler, Santarelli & San Filipo, developed
algorithms that predict the cavity stability and sand production potential of
perforations using robust engineering tools such as Morita's finite element
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analysis. Kessler et al developed a semi-empirical approach based on a large
amount of successfully calibrated field data from the Mediterranean and North
Sea.
A comprehensive analysis of sand production potential requires a systematic
approach to the most important factors:
. Determine field stresses
Review drilling, coring, logging and testing information in detail
Obtain geological and geophysical analysis of the data available
Determine the static and dynamic properties of the rock
Determine the well orientation, azimuth and stress orientation
Determine the perforation density and phasing and the drawdown
Build a well or field working model with the information
Date 1/3/98 IPrep. by : IESLRef.
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RDS Resource - Premier Oil PIc
SectionNo.
Revision: A
Page No.: 97
Version: 1
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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wr i"en p ermi ssi on o f P rem ie r O il P LC.
.
.
.
.
-- ..
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7.2.2 Gravel pack completions
In a gravel pack, the annulus between the wellbore and a base perforated pipe
with its wire-wrapped screen is filled with gravel sized to prevent sand from the well
passing through the pack. The gravel is either packed into the screen at
manufacture (pre-pack) or subsequently placed downhole in the annulus between
the screen and the wellbore. Pre-packed screens have the advantage of not
relying on successfully placing the slurried gravel in the annulus. However, the
screen may be damaged when it is being run in and must also be protected from
plugging by fines during the installation. The main advantages and limitations of
gravel packing are:
-- Advantages
. Treatment does not depend on chemical reactions
. Productivity impairment is usually small
. Especially useful for controlling sand in long productive intervals
. Easier to apply in composite sand
Disadvantages
. Complicates workovers
. Screen damage from erosion and corrosion is a major concern
. Can be difficult to use in deviated and horizontal wells
. Flow control and isolation is more complicated.
The gravel size is an important factor in achieving a successful gravel pack. Much
work has been done to evaluate the effect of different gravel sizes on formation
sand of varying grain size, towards preventing or restricting sand invasion of the
pack and consequent impairment of production. The current method of sizing
gravel is based on work by Saucier who recommends that the median gravel size
should be six times the average size of sand grain. While there would be no major
sand invasion with a smaller ratio, the pack permeability would be significantly
reduced. Although permeability would remain high with a larger ratio, sand would
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get through to the production tubing. Recent work on pack invasion and plugging
has produced new information and guidelines that modify the Saucier criteria.
Screen selection
The screen mesh size should not be more than the minimum size of the gravel that
will be placed in the 1" - 2" annulus between the screens and sandface.
Gravelplacement techniques
Reverse circulation is a technique in which the slurried gravel is pumped down the
annulus and deposited outside the screen through which the carrier fluid is forced
for return to surface up the workstring. Once the lower section of the annulus has
been packed, the slurry continues to fill upwards until it reaches a tell-tale screen
placed about 45 ft above the main screen. A pressure increase at surface signals
arrival of the slurry at the tell-tale, indicating that the gravel pack is in place. In
cased and perforated zones the gravel is squeeze-packed into the perforations
before starting reverse circulation. This simple, gravity-assisted process is
reasonably fast and economical. Low annulus velocities may cause gravel
segregation during placement, while high velocities through the casing and
wellbore might collect dirt or scale that would reduce productivity.
In the Washdown Technique, the gravel is placed in the wellbore to a depth of
about 15 ft above the producing interval. Brine is then circulated through a
washpipe assembly at the foot of the screen to wash it down into the gravel. In
cased and perforated holes gravel is squeezed into the perforations before starting
the washdown. Small screens can be installed in existing wells using this relatively
simple process. In longer intervals (30-40 ft), differential settling of the larger
gravel sizes into the lower section may impair productivity from particular zones.
Also, gravel may not settle down after the washdown, to remain held up in the
annulus.
The Circulation Technique, one of the most widely employed, uses a packed-off
crossover to flow the slurry into the annulus from the tubing or workstring. The
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suspension fluid is then forced through the screen and back up the other side of
the crossover. The upper tell-tale screen is sited 30 - 60 ft above the main screen
to define the level the gravel will reach during the operation The risk of differential
settling is minimised by maintaining high fluid velocities, although this requires
higher pressure in the workstring and may cause some erosion of the slurried
gravel.
--
Date 1/3/98
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RDS Resource - Premier Oil Pic
SectionNo.
Revision:A
Page No.: 100
Version: 1
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7.2.3. Slotted liners and screens
Slotted liners - one of the earliest methods of sand control - are tubing sections,
which have a series of slots cut into the walls. The slot width is designed to initiate
inter-particle bridging across the slot and was originally considered should be twice
the diameter of the 10 percentile sand grains. However, it is now suggested more
conservatively that they should only be about the same size.
Wire-wrapped screens have a base pipe with slots or holes around the
circumference that is either single-wire wrapped or is surrounded by cylindrical
sieves of various mesh sizes. This allows fluid flow into the 10 but prevents sand
passing into the production string. A V-shaped or 'keystone profile' wire minimises
the plugging that often occurs with standard-profile wire. The largest possible 00
sand screens are used to fill the surrounding annular space and prevent the
collapse of unconsolidated reservoir sections.
A disadvantage of the system is the difficulty of selecting screens to maximise the
flow area while avoiding loss of productivity due to formation collapse. However,
these problems are now being reduced by recent improvements in screen design
which include improved wire spacing tolerances, new materials such as 'sintered'
metal tubing and pre-packed screens. Screen effectiveness has also been
improved by the newly developed expandable screen and by better quality control.
There are two main criteria for designing screen-completions:
. Hydraulic performance of produced fluids through the base pipe
. The effect on production of plugging in the screen or pre-pack
The hydraulic performance of the produced fluids through the base pipe only
becomes important when flow rates are high or the screen size is less than 2-3/8".
This factor plays a major role in high rate horizontal wells in the North Sea, where
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RDS Resource - Premier Oil Pic
SectionNo.
Revision:A
Page No.: 101
Version: 1
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the allowed drawdown is only a few psi and reservoir pressure is very close to
bubble point.
7.2.4 Selective perforations
-
In a reservoir that is sufficiently thick and has good vertical hydraulic
communication through the different layers, it is possible to selectively perforate
higher strength layers. However, the best producing zones are usually the weaker
rock layers, which act as naturally propped fractures of large surface area and high
conductivity in conveying hydrocarbons from the reservoir mass to the wellbore.
The critical issue is then whether the well can reach either its production target orI
tubular limits without perforating these stronger layers. This must be established by
simulation and/or testing in delineation or early production wells.
When completing a well it is important to remember that it is much easier to add
perforations than to resolve the problems caused by there being too many.
Nonetheless, completions engineers are often surprised by how much can be
produced from high density perforations in a moderate zone. It should be noted
that selective perforations always generate a positive geometric skin that cannot
be removed by stimulation. However, a number of reservoir engineering tests have
correlations for estimating the magnitude of this skin.
Other sand control techniques include chemical treatments such as Formation
Consolidation, in which synthetic resins are injected into the reservoir rock. This is
suitable for high porosity thin «10ft) layers and has the advantage that the
treatment can be carried out through tubing after problems develop. Conversely,
there are problems with fluid placement into the matrix while consolidation
treatments have only a limited life span.
The key to employing any sand control technique is to identify the potential sand
producing zones from drilling, log and other analyses and then select the best
method of control.
Date 1/3/98 Prep. by: IESL Guidelines to Well Completion Design Section No. Page No.: 102+ I DJ
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7.2.5 Through-tubing sand control in existing completions
Throu9h-tubing techniques now provide cost-effective sand control for a variety of
conditions in existing wells. These techniques are designed to counteract the
effects of changing reservoir properties, sand production or completion failure that
may be reducing production rates. The precise gravel-packing method used
depends on the existing wellbore configuration and the completion equipment
installed.
Original production packer and completion equipment remain
place during the treatment reducing costs and logistic
Reduced risk of damage to the formation through shorter
exposure to potentially damaging fluids
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Advantages .
in
problems
-.-< .
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-
8 Operational aspects of well completions
There are many aspects to the installation operations fo~a well completion, but the
primary objective is to ensure that the system will perform as designed under
actual production conditions. This section reviews some of the important factors in
preparing, running and retrieving a completion string. Also included are general
procedures for some of the more common well intervention operations using
wireline and coiled tubing.
8.1 Installing and retrieving the completion string
The preliminary phase of a completion installation is concerned with equipment
and logistics preparation. With this completed, the first site operation is handover
of the well from drilling (or production) to the completions team. However, there is
no industry uniformity to the organisation of completion installations as every
company takes an individual approach - with some completion operation carried
out by drilling personnel.
8.2 Well handover - general procedures
-NO INPUT SUPPLIED -
8.2.1 Component testing
-NO INPUT SUPPLIED -
Date 113/98 IPrep. by : IESLRef.
Section No.
Revision: A
Page No.: 105
Version: 1
Guidelines to Well Completion Design
RDS Resource - Premier Oil PicThis document contains CONF IDENT IAL and PROPRIETARY INFORMAT ION of P remie r O il P lC. This d oc ument and t he inf ormat io n disclosed withinshal l not be reproduced in whole or inpart to any thi rd party any
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8.3 Wireline operations
Well maintenance, remedial work, control and safety functions are among the
many operations performed with wireline services that save money and time if
carried out efficiently and safely. However, wireline applicability can be restricted
by such factors as corrosion, sand and scale, well deviation and equipment. The
two main types of wireline operation are:
. Solid line (also known as slick line or solid wire)
. Multi-strand (braided line or wire line)
. Electric wireline
As electric wireline is mainly restricted to logging operations, only slick line and
multi-strand cables are reviewed here. These evolved from the flat, graduated
cable that was used for depth-measurement in shallow wells.
Wireline is currently run in almost every type of well for such diverse purposes as
monitoring physical variables (pressure, temperature, dimensions), active removal
procedures in the wellbore (wax, sand), installing and retrieving equipment (safety
valves, plugs, pressure regulators) and running measuring instruments. Various of
these operations are performed under wellbore pressure.
8.3.1 Equipment
Cable material
Because wireline cable must have a high strength:weight ratio, the commonest
material used is improved plow steel (IPS) which has high ultimate tensile strength
and ductility, at relatively low cost. IPS performs better in corrosive conditions than
more expensive materials, provided it is used with a corrosion inhibitor. Although
IPS can be used with inhibitor for high load, long duration operations in sweet
wells, only short running times are possible with heavy loads in sour wells. High
Date 1/3/98 IPrep. by : IESLRef.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision: A
Page No.: 106
Version: 1
This document contains CONFIDENTIAL and PROPRIE TARY INFORMATI ON of Premi er Oil P LC. This document and the infonnatlon disclosed within shall not be reproduced in whole or in par t t o a ny t hi rd par ty any
purpose whatsoever including conceptual design, engineering, manufaduring or construcUon without the express written permi ssion of Premi er Oi l PLC.
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H2Sconditions requires the use of other materials, although they may have lower
tensile strength.
Though generally least considered, the bending stresses to which the line is
subjected are the main cause of failure. Each trip in the well, the line passing
repetitively over the pulley causes about 14 fatigue bending cycles. It is
recommended that 50 m of cable should be discarded every time a new
connection is made.
Equipment
The surface assembly comprises the following components:
. Stuffing box (also known as seal wiper box or grease injector head)
. Lubricator
. Quick unions
. Tree connection (or Crossover)
. Ginpole and rope blocks
. Sensor for Martin Decker weight indicator
. Lifting clamp
. Hay pulley
. Wireline clamp
. Wireline sealing devices
The sealing device for solid wireline is a lubricator-mounted stuffing box that seals
around the cable under both static and dynamic conditions. In addition to the
5,000 psi rated standard model, a 10,000 psi high pressure version is also
available. Most stuffing boxes also contain a BOP plunger that seals off flow if the
wireline breaks and is forced out of the packing section.
For 3/16 inch braided cable, a line wiper (otherwise wiper box or stuffing head)
provides up to 500 psi static seal, but under dynamic conditions gives only a partial
seal, leakage being minimised by adjusting the compression on the rubber
Date 1/3/98 I Prep. by: IESL ~Ref.
Guidelines to Well Completion Design
RDS Resource - Premier OilPIc~ Section No.Revision: A ~ Page No.: 107Version: 1
Thisdoc ument c ont ains CONF IDENT IAL and PROPRIETARY INFORMAT ION o f Pr em ier O il PLC. This d oc ument and the infonnatlon disclosed within shall not be reproduced in whole or In part to any third party any
purpose whatsoever including conceptual design, engineering, manufaduring or construction without the express wri tten pennission of Premier Oil PLC.
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....
element. Better sealing is obtained with the grease injector head that extrudes very
high viscosity grease around the line as it passes through close-fitting flow tubes.
Although the assembly is designed to hold up to 5,000 psi, it is difficult to achieve
100% sealing. The equipment required to supply pressurised grease includes:
. Grease injector head assembly
. High pressure grease pump
. Grease reservoir
. Compressor
. Hoses
. Wiper box
. Sheave
. Crane
Lubricator
The lubricator is a tube with quick connections at each end that enables tools to be
run into and withdrawn from a pressurised wellbore. Threaded connections can be
used for wellhead pressures up to 5,000 psi, but above that level the quick
connections must be welded in position, then x-rayed and pressure tested before
use. Lubricator pressure limits are tabulated below.
Lubricator test and working pressures
Working Pressure [psi]
3000
5000
10000
Test Pressure [psi]
4500
7500
15000
The standard length of lubricator is 8 ft, but shorter 4 - 5 ft lengths are available.
The lower section should be of adequate diameter to take any tool that is to be
run, while the total length must be sufficient to accommodate the entire tool string
Date 1/3/98 I Prep. by : IESL ~ef.
Guidelines to Well Completion Design
RDS Resource - Premier Oil Pic i Sect/on No.evision: A iPage No.: 108ersion: 1
This document contains C ON FI DE NTI AL a nd P ROP RI ET AR Y I NFO RM ATI ON ofPremier Oil PLC. This document and the information disdosed withinshal l not be reproduced in whole or in part to any third party any
purpose whatsoever indueling conceplual design, engineering, manufacturing or c onst ruct ion w ithout the exp ress wri tten permiss ion of Premier Oil PLC.
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and any items being recovered. Lubricators should be x-rayed, magnifluxed for
cracks and visually inspected at regular intervals, with a particular check of the
internal walls for wire-tracking damage that could reduce their strength
significantly. HzS-resistant lubricators are required to be used if a well has more
than 10 ppm HzS.
Quick unions
The connections used to assemble the wireline service lubricator and associated
equipment are known as quick unions. They are designed to be made up only by
hand, so collar and union should never be loosened with pipe wrench, hammer or
chain tongs. If a quick unio!l cannot be hand-turned easily, it must be assumed
that there is still internal pressure that will have to be released using all appropriate
precautions. The box end of the union has an external ACME thread and accepts a
pin with O-ring seal whose internally threaded collar is then hand-made up to the
box when the pin has shouldered out. As the O-ring forms the pressure-retaining
seal, it must be carefully inspected for damage before making up the union.
Blow-out preventers (BOP)
Wireline BOPs are normally installed between the tree and the lower lubricator
section. They can be placed above the upper section for running or pulling an
SCSSV or wireline-retrievable BVP, although another option is to place a second
BOP immediately below the stuffing box. This provides a means of isolating well
pressure and recovering the tools if the wire breaks at the rope socket and drops
the tools across the christmas tree valves.
A wireline BOP holds pressure in one direction only. Its purpose is to:
. isolate well pressure without cutting the wire
. allow deployment and retrieval of wire cutting devices above the well BOPwhen the BHA is stuck in the hole
. permit the wire to be stripped through closed rams in emergency
Date 1/3/98 Prep. by: IESL Guidelines to Well Completion Design SectionNo. Page No.: 109
Ref. RDS Resource - Premier Oil Pic Revision: A Version: 1
Thisdocument contains CONF IDENT IAL and PROPRIETARY INFORMATION of Pr em ier O il P LC. Thi s doc ument a nd t he i nf or ma ti on d is cl os ed w it hi n s ha ll n ot b e r ep ro du ce d i n w ho le o r i n p a rt to any thi rd par ty any
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When the rams close they seal against the wire either mechanically or
hydraulically. The blind rams used for slick line (0.092", 0.105/0.108") and braided
line (3/16",1/4", conductor cable) are:
Slick line. Rams have rubber inserts on the sealing faces to allow sealing
with or without wire across them
· Rams have a semi-circular groove in the seals matching the
diameter
Braided line
line
These types of rams are manufactured by Otis, Bowen and Hydrolex. Common
BOP configurations are:
-- . Single ram BOP installed between the tree and lower lubricator
. Dual or twin ram BOP used mainly with braided line. Single casting with two
pairs of rams, usually hydraulically operated. Two single BOPs can be placed
one above the other, but the configuration is less convenient than a single
unit.
. Multiple ram BOP is used for high pressure gas wells, with a third ram
recommended. The lowest set of rams are installed upside down to contain
pressure from above. Grease injected above the rams forms an efficient seal.
. Equalising BOPs have a means of equalising pressures above and below as
opening the rams without doing so can damage the mechanism. The correctly
installed equalising assembly should have an Allen screw on the high pressure
side of the rams. The equalising valve should be kept closed at all times.
All types of BOPs must be regularly workshop tested to confirm that they are
satisfactory for field operations. With the rams open, the body should be tested to
150% MAWP, then the closed rams tested to 100% MAWP. The rams should be
closed before removing the BOP from the wellhead, then the handles removed for
transportation to prevent accidental bending of the threaded stems and to avoid
thread corrosion.
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 110Ref. I I RDS Resource - Premier Oil Pic TRevision : A IVersion: 1
This d oc umen t c ont ain s CONF IDENT IAL an d PROPRIETARY INFORMATION o f P rem ie r O il PLC. This document and the information disclosed within shall not be reproduced in whole or Inpart to any third party any
purpose whatsoever induding conceptual design, engineering, manufacturing or construction without the express written permis sio n of P rem ie r O il PLC.
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Weight indicator
A Martin Decker is the most common of the weight indicators. These show tension
changes resulting from variation of fluid level or density, prevent overloading of the
wireline and indicate jarring action as well as the position of the downhole
equipment. The sensor is attached to the tree and a heavy duty hose transmits the
hydraulic signal to the fluid-filled gauge. System accuracy depends on precisely
locating the sensor so that the line is at right angles to the hay pulley.
Haypulley
The hay pulley brings the wireline down from the stuffing box parallel to the
lubricator to form a right angle at the base to reduce side loading. The pulley is
hooked directly into an eye in the weight indicator sensor.
Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design I SectionNo. IPageNo.: 111
Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1
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purpose whatsoever including conceptual design, engineering I manufacturing or construction without the express wrihen pennission of Premier Oil PLC.
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8.3.2 General operating procedures
8.3.2.1 Rig-up procedure
. Rig personnel must be made fully aware of the safety aspects of operations by:
1 Safety meetings held with both shifts (repeated after any crew changes)
2 Erecting safety barriers
3 Ensuring familiarity with and adherence to emergency procedures
4 Strictly conforming to permit-to-~ork procedures.
. Prior attention (pre-rig-up) should be given to:
1 Valid certification for all equipment
2 BOPs have correctly sized rams
3 Sufficient wire on the unit
. Wireline engineer to confirm that equipment is ready for rigging up
. Great care should be taken with operations on the BOP deck, especially when
overhead cranes are being used
. All equipment to be securely tied down
Pressure testing
. Riser elements between production tree and wireline BOPs to be pressure
tested in place
. Wireline BOPs to be pressure tested with the test rod, taking precautions to
avoid the rod being blown out of the well or falling downhole. Test pressure
shall be 120%of expected wellhead pressure and conform to local regulations.
Pressure testing is carried out prior to the first wireline rund only.
. Wireline tools to be made up and zeroed appropriately
. After rigging up the wireline pressure control equipment with the wireline, the
tools are to be pulled into the top of the riser. All hydraulic hoses to be
connected and wireline pressure equipment to be function tested.
. The system to be pressure tested to the levels previously used.
Date 1/3/98 IPrep. by: IESLRef.
Guidelines to Well Completion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision:A
Page No.: 112
Version: 1
This document c ont ai ns CONF IDENT IAL a nd PROPR IETARY INFORMATION of P remi er Oi l P LC. Thi s do cument and the infoona tion disclosed withinsha ll not be reproduced in whole or in par t to any third party any
purpose whatsoever including conceptual design, engineering, manufac tu ri ng o r constNc ti on w ithout the express written pennission of Premier Oil PLC.
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. After consultation between all relevant parties the well is to be opened and the
wireline tools run in the hole. The number of turns required to open the swab
valve is to be recorded.
8.3.2.2 Running in and pulling procedure
In most wireline operations the first operation to be carried out is a drift run with
gauge cutters to check the condition of the tubing. Scale build-up, obstructions, or
even tubing collapse problems can thus be identified early and corrective
measures taken. The general running and pulling procedure is:
. Rig up and pressure test well control equipment as previously specified
. Well sketch to be made available to the winch operator so that care is taken
when passing restrictions in the well
. Running speed to be at the discretion of the winch operator but not to exceed
300 fUmin
. Pick-up tension checks to be recorded regularly. Tension to be observed when
setting or retrieving a downhole device.
. Safe working loads to be adhered to at all times
. On pulling out of hole winch cut-off tension to be set close to normal value,
especially near surface when running speed is to be reduced to a minimum.
. Toolstring to be recovered into the riser at minimum speeds using all routine
safety procedures
. Swab valve to be closed slowly, counting the turns, to ensure that the toolstring
is not across the valve
. Bleed off pressure from lubricator and riser and then break out the toolstring
DHSV installation and testing
. DHSV to be fully pressure tested at surface
. DHSV and required downhole equipment to be installed in the riser as
previously specified
. While running in hole the control line to be flushed with fresh hydraulic oil
Date 1/3/98 Prep. by: IESL Guidelines to Well Completion Design SectionNo. PageNo.: 113
Ref. RDS Resource - Premier Oil PIc Revision: A Version: 1
This doc ument o ont ai ns CONF IDENT IAL and PROPRIETARY INFORMATION o f Pr em ier O il PLC. Thi s document and the infconation disclosed withinshal l not be reproduced in whole or i n p ar t t o an y t hir d party any
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. Valve to be stopped 5 ft above the nipple and flushing continued until hydraulic
oil has been completely changed. Pumping then to be stopped.
. Valve to be landed in the nipple
. Setting pins to be sheared by jarring
. Valve to be pressure tested to the level specified bymanufacturer
. Overpull of 400 Ib to be applied to confirm correct landing then release pins to
be sheared
. On pulling out of hole, tell-tale spring on the running tool to be confirmed as in
the top groove before returning DHSV to platform control when backflow in the
control line is to be checked for 15 min.
DHSV retrieval
. DHSV to be retrieved with a pulling tool
. After running in hole the DHSV lock mandrel to be latched
. Control line pressure to be bled down and the line isolated at the Kerotest
valve or equivalent
. Jarring-up to be started to recover the valve
. Pullout of holefollowingtoolstringprocedurepreviouslyspecified
Setting and pressure testing of plugs set in DHSV nipples
. Pack-off and required downhole equipment to be installed in riser as previously
specified
. While running in hole the control line to be flushed with fresh hydraulic oil
. The pack-off to be stopped 5 ft above the nipple and flushing continued until
hydraulic oil has been completely changed. Pumping then to be stopped.
. The pack-off to be landed in the nipple
. Setting pins to be sheared byjarring
. Pack-offto be pressuretestedto the levelspecifiedbymanufacturer,butnotto
exceed the DHSV pressure test
. Overpull of 400 Ib to be applied to confirm correct landing then release pins to
be sheared
Date 1/3198 IPrep. by : IESL I Guidelines to Well Completion Design I Section No. IPage No.: 114
Ref. I I RDS Resource - Premier OilPIc I Revision: A IVersion: 1
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. On pulling out of hole, tell-tale spring on the running tool to be confirmed as in
the correct position
. Procedures to be repeated to set the prong in the pack-off or plug body
Downhole assembly to be pressure tested by slowly bleeding off wellhead
pressure at the test separator. Wellhead pressure to be less than 1 bar for a
valid test. After any pressure increase over 15 minute period indicating a faulty
prong, faulty pack-off or both, the prong to be re-run first then followed by
pack-off. Pressure from above to be applied by inhibited seawater or nitrogen.
---
Date 1/3/98 Prep. by: IESL Guidelines to Well Completion Design Section No. Page No.: 115
Ref. RDS Resource - PremierOil Pic Revision: A Version: 1
This document contains CO NF IDE NT IAL and P ROP RI ET ARY I NF ORM AT IO N o f P re mie r O il PL C. T his d oc ument and the information disclosed within shall not be reproduced in whole o r i n p ar t toanyth ird party anypurpose whatsoever including conceptual design. engineering, manufacturing or construction without the express wrlUen permission of Premier Oil PLC.
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X4. Electric line
X.4.1 Rig Up Procedure - FOLLOWING IMPORTED FROMABOVE -
(with 200 ft running speed max)
. Rig personnel must be made fully aware of the safety aspects of operations by:
1 Safety meetings held with both shifts (repeated after any crew changes)
2 Erecting safety barriers
3 Ensuring familiarity with and adherence to emergency procedures
4 Strictly conforming to permit-to-work procedures.
. Prior attention (pre-rig-up) should be given to:
1 Valid certification for all equipment
2 BOPs have correctly sized rams
3 Sufficient wire on the unit
. Wireline engineer to confirm that equipment is ready for rigging up
. Great care should be taken with operations on the BOP deck, especially when
overhead cranes are being used
. All equipment to be securely tied down
Pressure testing
. Riser elements between production tree and wireline BOPs to be pressure
tested in place
. Wireline BOPs to be pressure tested with the test rod, taking precautions to
avoid the rod being blown out of the well or falling downhole. Test pressure
shall be 120%of expected wellhead pressure and conform to local regulations.
Pressure testing is carried out prior to the first wireline rund only.
. Wireline tools to be made up and zeroed appropriately
. After rigging up the wireline pressure control equipment with the wireline, the
tools are to be pulled into the top of the riser. All hydraulic hoses to be
connected and wireline pressure equipment to be function tested.
Date 1/3/98 IPrep. by: IESLRef.
Guidelines to WellCompletion Design
RDS Resource - Premier Oil PIc
SectionNo.
Revision: A
Page No.: 116
Version: 1
This document contains CONFIDENTI AL and PROPRIETARY INFORMATION of Premier Oil PLC. This documen t and the i nforma ti on d iscl osed w ithi n sha ll not be rep roduced in whole or in par t to any t hi rd p ar ty an y
purpose whatsoever including conceptual design, engineering. manufacturing or construction without the express written permission of Premier Oil PLC.
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. The system to be pressure tested to the levels previously used.
. After consultation between all relevant parties the well is to be opened and the
wireline tools run in the hole. The number of turns required to open the swab
valve is to be recorded.
-
Running in and Pulling Procedures
. Rig up and pressure test well control equipment as previously specified
. Well sketch to be made available to the winch operator so that care is taken
when passing restrictions in the well
. Running speed to be at the discretion of the winch operator but not to exceed
200 fUmin
. Pick-up tension checks to be recorded regularly. Tension to be observed when
setting or retrieving a downhole device.
. Safe working loads to be adhered to at all times
. On pulling out of hole winch cut-off tension to be set close to normal value,
especially near surface when running speed is to be reduced to a minimum.
. Toolstring to be recovered into the riser at minimum speeds using all routine
safety procedures
. Swab valve to be closed slowly, counting the turns, to ensure that the toolstring
is not across the valve
. Bleed off pressure from lubricator and riser and then break out the toolstring
Special Precautions
Through tubing perforating
. Tubing displacement operations may be carried out either before or during
perforating operations.
. Control room to be kept informed of operations, especially when:
· Arming guns
Date 1/3/98 Prep. by : IESL Guidelines to Well Completion Design Section No. Page No.: 117
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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written pennisslon of Premier Oil PLC.
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· Guns are below 1,000 ft on RIH.
· Firing the guns.
· Guns are above 1,000 ft on POOH.
· Disarming guns.
. Prior to arming the guns all explosive safety guidelines must be adhered to. If
any procedure can not be followed for whatever reason, operations must be
suspended
. No explosives to be in the well during pressure testing of surface equipment
. CCl reference log to be made available to the wireline engineer