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

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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

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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

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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.

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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

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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


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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

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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


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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

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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

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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


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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



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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

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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

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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


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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


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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


EPDM Ethylene-propylene-diene (unsaturated) Nordel

3. Oil resistant - Low temperature


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

Date 1/3/98 IPrep. by : IESL I Guidelines to Well Completion Design I Section No. IPage No.: 21


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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

Date1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design I SectionNo. IPage No.: 22

Ref. I I RDS Resource - Premier OilPIc I Revision: A IVersion: 1

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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.


RDS Resource - Premier OilPIcJSection No.

Revision: AJPage No.: 26

Version: 1

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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

Date 1/3/98 IPrep.by: IESL T Guidelines to Well Completion Design ISectionNo. IPage No.: 28


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purpose whatsoever inchxjjng conceptual design, engineering, manufacturing or construction without the express written pennission of Premier Oil PLC.



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.

Date 1/3/98 IPrep.by: IESL I Guidelines to WellCompletion Design ISectionNo. IPage No.: 30


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purpose whatsoever Including conceptual design, engineering, manufacturing or construction without the express written pennission of Premier Oil PLC.



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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purpose whatsoever including conceptual design. engineering, manufactur ing or construction without the express written p ermissi on o f P re mier Oil P LC.



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.

Date 1/3198 IPrep. by : IESL I Guidelines to Well Completion Design I Section No. IPage No.: 41


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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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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written permission of Premier Oil PLC.



-

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.

Date 1/3/98 IPrep. by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 43


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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


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


Packer release

Anchor release


Operating loads


I

Axial loads


Stress

Check effects of temp. &

pressure changes for

pressure test ing, well ki lland stimulation


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

Date 1/3/98 IPrep.by: IESL I Guidel ines to Well Completion Design ISectionNo. IPageNo.: 45Ref. I I RDS Resource - Premier Oil Pic I Revision: A IVersion: 1This document contains CONFIDENTIAL and PROPRIETARY INFORMATION ofPremier Oil PLC. This document and the information disclosed withinshal l not be reproduced In whole or inpart to any thi rd par ty any

purpose whatsoever Including conceptual design, engineering, manufacturing or construdion without th e express written permissi on of P re mier Oi l PLC.



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

Date 1/3/98 IPrep. by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 50


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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

Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. 1Page No.: 52

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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.



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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.


RDS Resource - Premier Oil PIc

SectionNo.

Revision: A

Page No.: 55

Version: 1

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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

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purpose whatsoever Including conceptual destgn. engineering, manufacturing or construction without the express written permission of P remie r 01 1PLC .



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



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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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-

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


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purpose whatsoever including conceptual design, engineering, manufacturing or construdkm wi thout t he express writ ten pennission of Premier Oil PLC.



-

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

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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

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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

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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. .



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




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.

-


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.



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.



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.


Guidelines to WellCompletion Design


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 .



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


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.



...

-- ,,--~-

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

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Date 1/3/98

Ref.

Prep. by : IESL Guidelines to Well Completion Design


SectionNo.


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 -



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


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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 ,



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


This document contains CONF IDENT IAL a nd PROPR IETARY INFORMATION of P remi er Oil PLC. This document and the in(onnation disclosed within shall not be reproduced in whole or in par t to any t hird party any

purpose whatsoever including conceptual design. engineering, manufacturing or oonstruction without the express written permission of Premier Oil PLC.



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-

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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.



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

purpose whatsoever including conceptual design. engineering, manufacturing or constNdion without the express written permi ss ion o f Premier Oil PLC .



-

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.



SectionNo.

Revision: A

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Version: 1

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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 .



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

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Prep. by : IESL Guidelines to Well Completion Design


SectionNo.

Revision: A

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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



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.



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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express \Wine" pennisslon of Premier Oil PLC.



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



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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 .



. 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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purpose whatsoever Induding conceptual design. engineering, manufacturing or construction without the express written permission of Pr emi er Oi l P LC.



....---

· 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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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

Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 84Ref. 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 P LC. This document and the Information disclosed within shall not be r ep roduced i n who le o r I npa rt t o any t hi rd par ty any

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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.



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for convenience:

Bellows factor: Fb = Abl (Ab - Ap)

Port factor: Fp = Api (Ab - Ap)

Stem factor: Fs = AsI (Ab - Ap)



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

Date 1/3/98 IPrep.by: IESL I Guidelines to Well Completion Design I Section No. IPage No.: 87


This document contains CONF IDENT IAL a nd PROPR IETARY INFORMATION of P remi er Oil PLC. This document and the Information disclosed within shall not be reproduced In whole or i n p art t o any t hi rd p ar ty any

purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written permission of Premier Oil PLC.



...

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

Date 1/3/98 I Prep. by : IESLRef.



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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.



'\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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purpose whatsoever i"dueling conceptual design, engineering. manufacturing or construction without the express wri tten permission of Premier Oil PLC.



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

Date 1/3/98 IPrep. by : IESL I Guidelines to Well Completion Design ISectionNo. IPage No.: 90Ref. I I RDS Resource - Premier Oil PIc I Revision: A IVersion: 1

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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,



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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wrinen permission of Premier Oil PLC.



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

Ref.


RDS Resource - Premier Oil PIcSectionNo.

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purpose whatsoever including conceptual des ign, eng inee ri ng . manufac tu ri ng o r construction without the express written permi ss ion o f Premier Oil P lC .



· Packers and anchor tools for isolating or anchoring the CT

completion

-



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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wriUenpennission of Premier Oil PLC.



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.


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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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written pennission of Premier Oil PlC.



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

Date 1/3/98 IPrep. by : IESL I Guidelines to WellCompletion Design ISectionNo. IPage No.: 96


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purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written p ermi ssi on o f P rem ie r O il P LC.



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.



SectionNo.

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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.

.

.

.

.

-- ..



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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Version: 1

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pumose whatsoever including conceptual design, engineering, manufac tu ri ng o r const ruct ion w ithout the express written permission of Premier Oil PLC.



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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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

Ref. RDS Resource - Premier Oil Pic Revision:A Version: 1

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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



This document contains CONFIDENTIAL and PROPRIETARY I NFORMATI ON of Premier Oil PLC. This document and the information disclosed within shall not be reproduced in whole o r i n p ar t t o an y t hir d par ty anypurpose whatsoever including conceptual design. engineering, manufacturing or construction without the express wr in en pe rmi ss ion of P remi er O il PL C.

Advantages .

in

problems

-.-< .



-

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.

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Revision: A

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purpose whatsoever Induding oonceptual design. engineering, manufaduring or construction without the express written pennission of P remie r O il PLC .



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.



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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.


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purpose whatsoever including conceptual design, engineering, manufaduring or construction without the express wri tten pennission of Premier Oil PLC.



....

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.


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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.



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

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purpose whatsoever including conceptual design. engineering, manufaduring or construcUon without the express wriUen permIssion of Premier Oil PLC.



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

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purpose whatsoever induding conceptual design, engineering, manufacturing or construction without the express written permis sio n of P rem ie r O il PLC.



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


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purpose whatsoever including conceptual design, engineering I manufacturing or construction without the express wrihen pennission of Premier Oil PLC.



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.




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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.



. 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


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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

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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.

---


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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.




SectionNo.

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purpose whatsoever including conceptual design, engineering. manufacturing or construction without the express written permission of Premier Oil PLC.



. 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.



· 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

129842114 well completion design guideli[1]

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