129842114 Well Completion Design Guideli[1]

GUIDELINES FOR WELL COMPLETION DESIGN CONTENTS

1.

PREFACE

2.

INTRODUCTION

3.

ORGANISATIONAND RESPONSIBILITIES

4.

3.1

Technical role - Responsibilities

3.2

Operational role - Responsibilities

WELL COMPLETIONDESIGN 4.1

Role of the completions engineer

4.2

Developing a design philosophy

4.3

Defining well barriers

4.4

Defining materials and sealing requirements

4.4.1

Materials

4.1.1.1 Cast 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

4.4.2.2 T-seal (GT ring) 4.4.2.3 Chevron V-packing and bonded seals

4.4.2.4Packer elements 4.5

Types of completions

4.5.1

Open Hole 4.5.2 Slotted Liner

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5.

RESERVOIRANDWELL PERFORMANCE 5.1

6.

Basic principles of well deliverability 5.1.1

Inflow Performance

5.1.2

Vertical Lift Performance

5.1.3

Developing

6.2

6.3

6.1.1

Hydraulic performance

6.1.2

Mechanical loading

6.1.3

Material selection

Flow controls and isolation equipment 6.2.1 6.2.2

Safety valves Packers

6.2.3

Nipples, plugs and accessories

Special equipment and requirements

7.2

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Polished bore receptacles Formation isolation valves

COMPLETIONDESIGNFORSPECIALAPPLICATIONS 7.1

Date

model

Tubing design

6.3.1 6.3.2

Ref.

a well performance

SYSTEMDESIGN 6.1

7.

Relationship

Wells requiring artificial lift 7.1.1

Electrical Submersible Pump completions

7.1.2

Gas lift completions

7.1.3

Coiled Tubing completions

Completion design in wells with sanding problems 7.2.1

Sand production prediction

7.2.2

Gravel packed completions

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8.

7.2.3

Slotted liners and screens

7.2.4

Selective perforations

OPERATIONALASPECTS OF WELL COMPLETIONS 8.1

Installing and retrieving the completion string

8.2

8.1.1

Equipment preparation

8.1.2

Component testing

Wireline operations

8.3

8.2.1

Equipment

8.2.2

Type of operations

8.2.3

General operational procedures

Coiled Tubing operations 8.3.1

Equipment

8.3.2 Type of operations 8.3.3

General operational procedures

APPENDICES

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Appendix

1

Appendix

2

Appendix

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PREMIER OIL GUIDELINES FOR COMPLETIONS 1.

DESIGN

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 and well 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

.

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

Develop and/or supervise the selection of an optimum perforating strategy

Operational Responsibilities

. . . . . .

Organise the logistics and installation operations for the completion

.

Ensure implementation of all safety procedures and policies

.

Prepare operational reports

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

Any Completions Supervisor who may be given responsibility for the installation operations reports to the Completions Engineer.

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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 particular set of conditions willlead to a well-engineered solution. A clear completion philosophy must be defined at a very early stage in the project. As a main objective, the completion should be the simplest possible, in order to:

. . . . .

Maximise productivity Minimise initial CAPEX Minimise workover and intervention requirements

Minimise risk and safety exposure Maximise recovery by making provision for future operations

In certain situations some of these factors can be mutually exclusive, so that careful engineering is necessary to achieve an "optimum solution" compromise.

Defining well barriers One of the most important tasks in present day completion design is to understand and identify the well safety requirements. Formation and other pressurised fluids must be contained within the wellbore to prevent their Date 1/3/98 Ref.

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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

COMPONENT I BARRIER

LOCATION

POSITION

CCEPTABLE

COMMENTS

Wireline plugs

Subsurface

Tubing

Yes

Set in nipples

Tubing

Yes

Set in tubing only Tubing or wireline retrievable for either the tubing or annular space

Safety valves

Subsurface

Tubing or annular

Yes

Injection valves

Subsurface

Tubing

No

Could be accepted in water injection wells.

Fluid column

Subsurface

Tubing or annular

No

Not on its own, only if used with the mechanical barriers

Packers

Subsurface

Tubing or annular

Yes

Permanent or retrievable

Formation isolation valves

Subsurface

Casing

No

Burst disc

Subsurface

Tubing I Tail pipe

Yes

Most current1 valves only hold pressure from above Has been used in the UK

DST strings

Subsurface

Tubing

Yes

Tree valves

Surface

Tree

Yes

Riser systems

Surface

Subsea only

Yes

Suitably rated

Wireline plug or BPV BOPs

Surface

Tubing hanger Tree or riser section

Yes

Set on hanger profile

Surface

Yes

For intervention operations

Strippers Gate valves

Surface

Riser

Yes

Properly tested

Surface

Riser

Yes

Properly tested

Not to be used as a permanent barrier In some areas the whole tree is considered a single barrier

I New models can be used

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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 Fluid

SCSSSV

Column

Initial

.

Completion Production

- Subsea

well - UKCS

Surface I

Deep set

Shallow set

Christmas

Downhole

Injection

Injection

Tree

plug(s)

valve

valve

valves

.

.

.

.

.

.

Injection Combined

.

.

.

.

.

ProdIlnj Workover

.

Tree

.

Removal

. .

. .

.

.

.

.

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.

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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, in wells 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

CAST IRON

Grey cast iron Ductile cast iron White cast iron

Low carbon < 0.3 %

CARBON STEEL 1

High carbon 0.3% < C < 1.0 % Low % of :

LOW ALLOY STEELS

1

Chromium Molybdenum Nickel

Semi-stainless steel Martensitic Austenitic/Ferric Duplex

STAINLESS STEEL

High % of :

3

5 30 15

Chromium Molybdenum Nickel

EXOTIC ALLOYS

API grade.

COST RATIO

Titanium Brass & bronze Eintered carbides

50

Composites

60

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

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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 not heat 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 the mechanical properties. The most commonly added are:

.

chromium (Cr) at -1 % increases corrosion resistance, hardness, wear resistance and high temperature strength

- 0.2 % improves surface hardening and corrosion/wear

.

molybdenum (Mo) at 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 H2S SCC 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 . Cr 22%, 25%, 28% . 32% Ni, 28% Cr (Sanicro 28%; Cabval VS 28, etc) . Not suitable for H2S (unless has Ni content)

Duplex

. 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

. Very high resistance to e02 corrosion up to 100 psia partial pressures and at elevated temperatures

Incoloy

. 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 Pyromet 31 - high strength items (SSSVs, tools, nipples)

severe environments.

· 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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Yield Strength [kg/mm2]

H2S

cr

CO2

Carbon API Grade

50

Yes

-

No

Steel Well Grade

100

No -

-

No

-

-

Material

Stainless Steel Martensic

65

-

No

Yes

Duplex Austenitic

50

Yes

Yes

Yes

35

Yes

Yes

Yes

NiAlloy

50

Yes

Yes

Yes

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 by Waard and Milliams in the following equation:

Log R

= 8.78 -

Eq.

(2320/

[T + 273] ) - 5.55 X 10-3 T + 0.67 Log PC02

R

Corrosion rate in mil/year

T

Temperature in degrees Celsius

PC02

Partial pressure of the carbon dioxide content inPSI

Where

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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.

1~-.~':J~o ,

~~/,"'._.

<, - ',_

- ',' - - _: ":,

"

'.

, ""

- : 'I

~

"

'Qlu;:-:~oj "if~~~~ :'f~r~5, ,-J-_~~ ~~.,

100m

~~;:;~j"~o1 1000

27% a- -31%1'1 - 3.5 %Mo

27%a

42%N - 3 %Mo

i'I:S

'Cij 1 00

~ N

8u..

0 w c: (I')

10

(I')

w c:

c.

....I b:

API J-SS N-80

11

I

APll-80 G-75

0.1

I

I

CE 0.05 psi

O_O1l

0.001

I

0.01

I

I

I

0.1

1

10

PARTIAL PRESSIJtEOF

4.3.2

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10m

100m

H2Spsia

Sealing systems

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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 Maximin Static/cyclic, frequency

Surface and bottom hole temperatures Reservoir pressure Wellhead

Depletion/Abandonment

pressure

pressure

Closed in/flowing

Pressure profile

Variation, frequency,

Production fluid composition

Hydrocarbons,

rate

aromatics, water

Gas/oil ratio Injected fluids composition Inhibitors Control line fluids Completion fluids Acids, alcohol and chemicals Temperature

Strength, duration, frequency Corrosion and scale

of injected fluids downhole

Produced gas composition

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sulphide, carbon dioxide Differential

Level, rate, frequency

seal pressure

Seal movements

Travel, rate, frequency

.Lifetime required between workovers

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 and codes

1. Non oil resistance - General Purpose ASTM Code

Elastomer Class

NR

Natural rubber

Example SMR

2. Non oil resistance - medium heat resistance ASTM Code

Elastomer Class

EPDM

Ethylene-propylene-diene (unsaturated)

Example Nordel

3. Oil resistant - Low temperature ASTM Code

Elastomer Class

Example

TR

Polysulphide

Thiokol

AU/EU

Polyurethane (ester/ether)

Adiprene

4. Oil resistant - General purpose ASTM Code

Elastomer Class

Example

CR

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 ACM

Elastomer

Polyacrylic

type

Example Vamac

FCM FKM

Tetrafluoroethylene - propylene Fluoroelastomer

Viton

FFKM

Perfluoroelastomer

Kalrez

Aflas

6. Silicone rubbers

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ASTM Code

Elastomer

Example

type

SI

Silicone rubber

FSI

Fluorosilicone rubber

Most sealing systems for both static and dynamic conditions are based on either axial 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 a rectangular-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 packing arrangements are illustrated on the next page.

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Seal Types

o

Chevron seal

Ring sack

0- Rng

MtOtt!l :!de~or EleeJX:irnel

4.4.2.4

eeal

Packer elements

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.

.

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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 Tseals 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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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.

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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 ·

4.5.2

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

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

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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 Have minimum 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 High rate

FLOWING

. . .

Liner PBRs

Gas wells Oil wells Wells on gas lift

Tubingless Low rate Single string Multizone

High rate Parallel Concentric strings

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Significant differences between onshore and offshore well completions largely relate to the surface interfacing rather than the completion itself. However, each set of circumstances must be evaluated in developing a suitable completion philosophy and detailed design. The effects on completion design of the differences between these operating environments are reviewed below.

Completion cross-reference Location I Consideration Completion

type

accordinQ to operatinQ environment

Onshore

Offshore

Subsea

Cased & perforated Open hole Slotted liners

Cased & perforated Slotted liners 1

Cased & perforated

Slotted liners1

Design philosophy

Lower cost & productivity

Well performance

IPR and VLP

IPR and VLP

IPR and VLP

Artificialliff

Method selection and logistics

Method and interfaces with the platform systems

Production tree and hanger, riser and interfaces,

Sand production

Can be managed if < 50 Ibs /1000 bbls

Manageable depending on the installation capacity

Critical, not allowed

Tubing design Mechanical loading

Conventional DSF1 unless special conditions are specified

Conventional DSF1 unless special conditions are specified

Priority to collapse criteria, annular pressure needs to be bled off

Erosion

Only in special circumstances

Critical

Critical

Corrosion

Depending on severity, mainly prevention program

Material selection

Material selection

Safety valves

Not always required

Always required, tubing or wireline retrievable

ubing retrievable preferable based or hydraulics and reliability record. Critical item

Packers

Packerless is common unless is HP or gas well

Mainly packer type, other in particular circumstances

Packer type

Nipples

Minimum amount

Functionality

Functionality

Formation Isolation valves

Depending on the nature of the potential damage

Productivity

and safety

Productivity

Depending on the nature of the potential damage.

and safety

Recommended depending on interfaces with well functions

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.

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Multilateral wells in particular, have very effectively scaled down features of horizontal well technology to suit the reduced diameter of their main wellbore, although cost and limited equipment options have slowed implementation. The multilateral concept was first developed in Russia during the 60s, but had to be abandoned because of prevailing technological limitations.

Multifunction wells carry out more than one function with little modification to the main wellbore. This most commonly involves producing up the tubing while injecting down the annulus. In completion terms, this is an efficient option that, if properly managed, would reduce the number of wells required to develop a field. Some of the main completion issues to be addressed for a multifunction well are:

.

Mechanical loading on the tubing, particularly due to collapse

. . . . .

Axial movement of the tubing string due to temperature changes Well barriers and safety philosophy Erosion and corrosion of tubing and casing, both internal and external Operating and well maintenance philosophy Equipment sizes and performance expectations long term.

Intelligent or Smart wells are the latest advance in hydrocarbon production and may include multilateral or multifunction wells. Their concept of minimum well intervention for maximum control, initially developed for subsea wells, depends on installing in the well a considerable quantity of subsurface electronic data gathering/transmitting and control equipment. Completion design for these wells requires a proper definition of the functions and long term production strategy as it must accommodate the downhole controls that are surface operated. In most cases, flow from particular intervals is controlled by a series of hydraulically operated sliding sleeves, with signals transmitted to remote operating points through special cables and conduits.

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5

RESERVOIR AND WELL PERFORMANCE

5.1.1

Well Inflow Performance Relationship

The well Inflow Performance Relationship (IPR) quantifies the changes in pressure and flow rate as the reservoir fluid passes form the reservoir into the wellbore. The IPR was developed from Darcy's Law which defines the velocity of a fluid as a function of: the rock permeability, the fluid viscosity and density, the change in pressure along the fluid path and the change in elevation. Darcy's Law makes two important assumptions. Firstly, flow is assumed to be linear, Le. that the crosssectional 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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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

rw

Radius of the Wellbore

in or ft in orft as re

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 the

Darcy's equation assumes an infinite drainage volume for the reservoirs (Le. steady state) so further analysis is required to determine the drawdown in a semisteady 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:

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-2

dr_ 3.9764.10 .K-h.T S.Z 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 pseudopressure 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

r

.

:IEffect

-

of Drawdownl'

-

...J

/

/ Pw

OUl

down

--

-

I( )amaged Zone

... ~ CI)

,--

I/) I/) CI)

... Il.

Distance from Wellbore

rw

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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:

& K dP_/l'u

+ l3.p.u2..................... ..Eq.

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-

qs P e- P w

5.1.5

.Eq.

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.

·

Compaction skin 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.

S

=h

k

C LP ( ke

·

re

I.In-

)

( 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 of the damaged zone.

k

rd

S d= -

- 1 . In ( kd ) ( ( r w)

+S

k

+ -.s

P)

x

kd

..... ...... .. .. ... .... .Eq.

Definition of the nomenclature can be found in the texts[XI.

The change in IPR from an ideal to a more realistic model as various skin effects take effect round the wellbore is depicted in the following graph.

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5.1.2

Vertical lift performance

The vertical lift curve is a property both of the completion geometry and the reservoir fluids as they exist in the formation. Its mathematical form follows the laws of conservation of energy with different energy components as defined below. By plotting flow rate against pressure, system curves can be established that are used to determine the optimum production rate for a given system.

5.1.2.1

Tubing performance

By applying the conservation of energy principle a mathematical expression can be derived to describe fluid flow in a pipe, the sum of the energies being zero. The energy components are:

.

Internal Energy - a function of the entropy and enthalpy of the fluid

.

Energyof Expansion/Contraction - a 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: ~Ptub is the pressure drop in the tubing ~PhYdis the hydrostatic gradient ~Pfrcis the pressure drop due to the frictional forces ~Pke is the kinetic energy pressure drop (typically 1% of the total)

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The ultimate goal is to minimise hydrocarbons

the level of energy required to flow

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 wateroil 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

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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

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41

No.:

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to any third party

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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:

Date 1/3/98

Ref.

IPrep.by : I

Gravity

[ g I gc p Cos 8 ]

Friction

[ f p V 2 I 2 gc d ]

Acceleration

[ p v dv I gc dZ ]

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Numerical integration of these terms for each tubing section gives the total pressure difference

between reservoir and surface. The gravity term

is

predominant for single phase liquid production, but multi-phase systems require complex techniques to determine the partitioning of hydrocarbon mixtures into gas and oil phases. While hold-up effects, slippage between phases and fluid densities can be determined from PVT correlations, friction accounts for a large part of the overall head loss in high rate wells. The loss due to friction is normally in the range 5 - 25% but is occasionally more. The acceleration term usually arises from fluid expansion as pressure decreases towards the surface. Computer programs such as PROSPER and WELLFLOW are generally used for this type of computation in completion design. A NODAL analysis approach treats the well as a single system and integrates reservoir performance (IPR) and the VLP-based tubing hydraulic

-

performance. Detailed descriptions of IPR and VLP are given in Section 5.

6.1.2

Mechanical loading

It is essential that the mechanical attributes of tubing options are carefully reviewed to confirm their integrity under the expected operating conditions. However there are still significant uncertainties about these conditions that could affect the loading on the tubing. Despite the availability of analytical tools, tubing design has been mainly based on a semi-analytical approach. There are no universally accepted standards for tubing design although some national regulatory authorities specify minimum design criteria. As a result, each manufacturer has an individual design philosophy.

A number of analytical tools are now available for carrying out rigorous analysis of the loading that would be applied under particular operating conditions. As these should be used wherever possible, the analysis for a subsea well is given in Appendix **. Tabulated below is a typical set of tubing design criteria that includes recommended design factors for the most common operating conditions.

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TUBING DESIGN CRITERIA

CONDITION

LOADING

I

I

DESIGN CRITERIA

T DESIGN FACTOR

Burst

Flowing wells

Internal

Kill pressure on hydrocarbons filled tubing at squeeze rates> 2 ft/sec.

External

Packer fluid and no annulus pressure

Additional considerations Internal

Pressure test and stimulation

1.125

operations

Screen-out with max. sand concentration maximum pump pressure

and

External

Packer fluid and specified casing pressure

Additional considerations

Pressure test prior to the operation

Internal

Tubing empty to lowest possible fluid level

Fracturing strings

1.125

Collapse External

Flowing wells w/Packer/PBR

Pressurised

packer fluid in the annulus

1.125

Additional considerations I Check biaxial effects of tension on large 0.0. pipe. Pressure tests Tension Bouyant weight in completion fluid

Running & Pulling

All wells

Additional considerations

Drag forces particularly in deviated wells. Age and corrosion effects on the pipe

Packer release Anchor release

Buoyant weight of pipe in workover fluid

Wells w/packers or anchors

Additional

considerations

Shear pins type, number & rating. Age and corrosion effects on the pipe. Stuck seals

considerations

Body 1.3 Joint 1.5

Effective tension at surface

Operating loads Additional

Body 1.5 Joint 1.8

Pressure test on plugs above packer/anchor Cool down during stimulation of well kill. Packer or seal release Piston forces on swedges

Body 1.3 Joint 1.5

Compression Axial loads

All wells Total

I

Triaxial

Additional

Date 1/3/98

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set down and operating loads Total triaxial load

Body 1.5 Joint 1.8

Stress Check effects of temp. & pressure changes for

Normal operating conditions (Production / Shut in)

1.67

pressure testing, well kill and stimulation

Maximum loading conditions occurring infrequently (Well kill/stimulation)

1.25

Additional

Ref.

Combined

considerations

IESL

I

I

considerations

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)

2 7/8

2 3/8

SIZE [ In ]

3

REMARKS

WEIGTH [Lblft ] J55

L80

J55

L80

J55

L80

CS A95 501 CFJ-P

72000 67950 72000 47025

104175 98100 104175 67950

100125 87975 100125 66150

145125 128025 145125 95175

142200 133200 142200 96075

207225 194175 207225 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

GRADE HYDRIL

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6.1.3

Corrosion considerations

As corrosion effects were not covered in the review of equipment materials and sealing systems in Section 4.4, basic guidelines for wells liable to corrosion are presented here. Tabulated below are the main characteristics of the six basic types of corrosion.

TYPE

\/IECHANISM(S)

CONDITION

Sweet (CO2)

Mesa or pitting

Severe Common Rare

Sour (H2S)

Stress cracking Weight loss SRB

Chloride(CI)

Pitting

-

Salt water Anaerobic water

PARTIAL PRESSURE [psi] > 30 >10 >7 0.05 50

CI cone. Velocity Low pH Hea

MECHANISM OF CONTROL

REMARKS

Material selection Avoid high turbulence areas Coating Material selection Reduced at high temp. Chemical inhibition, Barnacle type of scale not Material selection seen in calipers High chrome alloy Inhibitors CP

Reduced Temporarily controlled

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

['

i

i

I

_

T INJECTION SAFETYVALVE

I

r

T

GASVENT SAFETYVALVES

GASVENT SAFETYVALVES

TUBING/ ANNULUS SAFETYVALVES

CONTROLLED

CONTROLLED

l=-=I:::~::::,:~~

~

Subsurface

Controlled

Subsurface

Safety Valves (SSCSSV)

developed. Because their closure mechanism was dictated by the downhole environment, they had several disadvantages:

.

Substantial reduction in flow area

.

Over-sensitivityto alternatingwell conditions

. .

Unresponsive to small surface leaks Difficulty of calibration

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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I '

Also, know as velocity valves or storm chokes, these were the first types to be

SSCSSVs

i i


party

any

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 r~lzlclon

I'" ",,'od\, "'IOUI/> taLeli!!t. rn Inclf:lltl!bd

p"' '" drop "'...ng a,. ",OIon up I!IQoIMla,. '!"''lI do~ng d,.

ftoppOI.

Seal

Spring

Piston

Flapper Restriction

Date 1/3/98

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Guidelines to Well Completion Design RDS Resource - Premier Oil PIc INFORMATION

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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 pressureson the surfaceand subsurfacesafetyvalves.An EmergencyShut-Down Loop (ESD) may have thermal sensors, high-low pilots and manual shut-down stations. SCSSVs are classified as either wireline- or tubing-retrieved,alternate designationsfor the latter beingTRSCSSVor 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

.

May have to be removed during wireline operations

. .

Flow rate restricted by the smalier-than-tubing ID

When closed may be blownfrom nippledue to wirelineoperatorerror or faulty locks

.

Control line fluid exposed to contaminating fluids in tubing before valve is

landed

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in the hydraulic nipple

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Tubing retrievable safety valves are made up on the running string and run in hole with the completion. Their advantages and disadvantages are:

Advantages

.

No restriction of flow rate as ID matches the tubing

. .

Wireline operations can be carried out through the compatible ID In the event of tubing retrievable valve failure a wireline valve can be landed in

it

. .

-

Control line fluid not exposed to well fluids during installation and retrieval Valve can be bridged during severe workover operations.

Disadvantages

.

Inaccessibility- the tubing mustbe pulledto retrievethe valve.

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 10,000 psi: 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)

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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

~ydraulic control line

PRINCIPLE

Loes ci h)l:haulic pressure albwa spring to p ush the piston up closng the lIapper valve

....

.

islon Seal

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Guidelines

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RDS Resource INFORMATION manufacturing

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6.2.2

Packer types

Packers are essential to a great many well completions, whether single or multiple zone. By physically isolating the casing/tubing annulus from the production zone they contribute to both well safety and production flow stability. The most common uses are:

.

- prevent formation fluids from entering the annulus

Well protection

- 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 H2S or 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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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.

-

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Classification of Packers

Packer Classification

I

Completion stage

-

Drilling I

stage

I

Setting/Seali ng

Completion type

I Retrievable

III

Stress state of the

Permanent

Permanent Retrievable

I

completion

-

string

Type of setting mechanism

Compression of the

Rota-mechanical set

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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 by milling.

Retrievable packers With a setting/unsettingmechanismthat can be either mechanicalor hydraulic,a retrievablepackeris frequentlypart of the completion.There are three categories:

.

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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Induding conceptual design. engineering, manufaduring

or construction without the express written permission of Premier Oil PlC.

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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1

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elements. In the slip and cone system, the activated cone is locked in position mechanically. The main techniques for plugging the tubing so that internal pressure can be applied include:

. .

Installation of a blanking plug in an appropriate nipple An expandable seat activated by dropping a ball, then after packer set, is

sheared out by applied pressure and drops into the well sump

.

A differential displacing sub through whose ports the tubing fluid is displaced

prior to setting the packer. When a ball is dropped it seats on an expandable collet that allows pressure to be generated. Overpressure then moves the collet downwards, closing the circulation valve and letting the ball drop through. Stress condition of the string

...

As the stress condition of the string is affected by well pressure and temperature variations in these may have significant stress effects on the string.

Classification by completion type Single zone completion Annular isolation is often desirable for completions designed to produce from a single zone, to avoid complications from any increase in casing head pressure at surface. A packer is used for such isolation, normally being set as close to the reservoir as possible to minimise the volume of gas trapped underneath.

Multiple completion packers In producing from multiple zones it is normally necessary to isolate from the annulus as well as between each zone. While permanent packers may be required for high pressure or other specific well conditions, retrievable packers are generally preferred because of the complexity of the completion. Multiple string packers are available with similar permanency and setting method specifications as single string packers, although the upper packer may not be wireline settable because of cable weight limitations. .

Date 1/3/98

Ref.

IPrep.by : I

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I I



CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the infonnation disclosed within shall purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express written pennission of Premier Oil PLC.

This document

contains

not be reproduced

IPage No.: IVersion: in

whole

63

1


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.

-

Date 1/3/98

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not be reproduced

IPage No.: 64 IVersion: 1 In whole

or in part


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 :


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This document contains CONFIDENTIAL including conceptual

purpose whatsoever


-

Ref. and PROPRIETARY

INFORMATION

of Premier

design.

manufacturing

or construction

engineering,

Oil PLC.

This

document

and the information

without the express written permission

disclosed

of Premier

within shall not be reproduced Oil PLC.

Page No.: 65 Version: 1 in whole


any

Non-selective or "no-go" nipples depend on the mandrel OD matching a restriction in the nipple ID

-a

larger OD mandrel being excluded but one of smaller OD

passing through without seating. The largest ID nipple is the topmost in the completion string, the ID of each nipple downwards being progressively smaller. While the ID-restriction of the nipple may be at the bottom of the profile, it is best to be at the top to lessen the risk of damage to the polished seal section.

Mandrels This is a device specifically designed to lock into the internal bore of a nipple and seal-oft in the sealing section of the ID. The mandrel is run through the tubing to the correct nipple where it will either seat (non-selective) or its locking pins will be activated (selective) and is then set into the nipple ID by,jarring upwards. Various mandrel types are illustrated below. - MANDREL DIAGRAM -

Accessories Nipple profiles obstruct production or injection flow because the convergence and divergence of the nipple system causes severe turbulence, that in turn can lead to erosion of the tubing and nipple system. Accessories such as flow couplings can be installed above and below a particular nipple to provide convergence and minimise abrasion by the flowing fluid. Flow couplings are subs manufactured of harder material than the tubing and normally have a larger OD to cope with potential erosion. Detailed size and type specifications for some nipples and components are tabulated below.

Date 1/3/98

Ref.

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Section No. Revision: A

This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the information disclosed within shall not be reproduced in whole purpose whatsoever including conceptual design, engineering, manufacturing or construction without the express wriUen penTIlsslon of Premier Oil PLC.

Page No.: 66 Version: 1 or In part to any third

party any

TYPE

MANUF.

COMPONENT

MOD. L

BAKER

MOD. X OTIS MOD. R

SLIDING SLEEVE

MOD. W MOD.C CAMCO MOD. DB

BAKER

Selective No-go Selective No-go Selective No-go Selective No-go Selective No-go Selective No-go Selective No-go Selective No-go Selective No-go

MOD. R

BOTTOM NO GO NIPPLE MOD. RN

OTIS

MOD. XN

BAKER

MOD. F

MOD. X OTIS MOD.R

TOP NO - GO SELECTIVE

MOD. ERA-1 BAKER

Date 1/3/98

I Prep.by :

Ref.

I

MOD. ELA-1

IESL

1.812 1.937 1.781 1.728 1.812 1.760 1.875 1.822 1.500 1.345 1.710 1.560 1.781 1.640 1.875 1.791

T I

3.312

2.062 1.978 2.250 2.197

2.562 2.442 2.750 2.697

3.125 3.072 3.312 3.242

-

-

-

2.188 2.010 2.312 2.131 2.562 2.329

3.125 2.907 3.250 3.088

1,875 1.716 2.000 1.821 2.125 1.937 2.188 2.010 2.312 2.205

1.781 1.812 1.375 1.375 1.905

2.062 2.250 2.312 2.312 2.380

-

-

1.500 1.710 1.781 1.562 1.312 1.765

1.875 2.000 2.125 1.875 2.000 2.062 2.125 2.188 2.250 2.062 2.250 2.312

1.781 1.812 1.875

- Premier Oil Pic

2.750 2.635 2.875 2.760 2.562 2.750 2.812 2.750 2.812 2.875 2.188 2.312 2.562 2.125 2.250 2.312 2.437 2.562 2.703 2.562 2.750 2.812

I SectionNo.

I Revision:

A

This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier OilPLC.Thisdocumentand the infonnationdisclosedwithinshall not be reproducedin purpose whatsoever induding conceptual design. engineering, manufacturing or construction without the express written permission of Premier Oil PLC.

-

3.812 3.437 3.688

-

-

-

4 1/2" 3.688 3.812

3.840

2.750 2.937

-

-

-


RDS Resource

2.250 2.351

-

MOD. 0

CAMCO

SELECTIVE RECEPTACLE

OUTERDIAMETER OF PRODUCTIONTUBING 4" 31/2" 2 3/8" 2 7/8" 3.1250 2.250 2.750 1.781 2.812 3.250 2.312 1.812 3.312 1.875 2.750 3.312 1.375 2.312 2.812 2.188 3.125 1.875 1.500 2.312 3.250 1.710 2.000 2.562 1.781 2.125 2.188 2.312 2.812 1.875

-

3.687 3.688 3.625 3.750 3.700 3.812 3.759 3.437 3.162 3.688 3.456

-

-

3.312 3.125 -

3.812 3.725

3.125 3.250 3.312 3.312

3.688 3.750 3.812 3.812

-

-

-

-

3.125 3.250 -

3.437 3.688 3.812 3.500 3.625 3.687 3.750 3.812 3.875 3.688 3.750 3.812

3.187 3.312

3.125 3.250 3.312

I Page No.:

IVersion:

,

67

1

wholeor in part to any third party any

--

COMPONENT

(

1.812 1.875

MOD L.J

CAMCO

TYPE

MANUF. MOD.SL

BAKER MOD.VL MODFVL MODFVL TUBING MOUNTED SAFETY VALVE

...

MOD. TRB-8-FSR MOD. TRDP-1A-SSA MOD. TRDP-2A-SSA MOD. QLP MOD. QLP MOD. DL

CAMCO

MOD. FMX Flapper MOD. FMR Flapper MOD. BMX

OTIS

MOD. BMR

Ball

MOD. BFX

BAKER WIRELlNE SAFETY VALVES

MOD. BFV BFVH MOD. BFVE BFVHE

MOD. WRDP-1 CAMCO

MOD. B7 MOD. WRDP-1

MOD.

Date 1/3/98 Ret.

IPrep.by : I

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I I

Guidelines

2.250 2.312

OUTERDIAMETER OF PRODUCTIONTUBING 4" 2 3/8" 27/8" 3 1/2" 4 1/2" 2.562 2.750 2.812 3.812 1.875 2.188 2.560 3.812 2.312 1.375 2.312 2.812 1.375 1.375 1.375 1.375 1.710 1.875 1.875 1.710 1.781

1.875 1.710 1.781

Ball

2.312 2.312 2.312 2.312 2.313 2.313

-

2.125 2.188

2.313

-

2.188 -

2.75 2.812 2.750 -

2.750 2.813 2.562 2.562 1.262 2.750

-

NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV

1.718 0.650 1.875 0.807 1.718 0.650 1.875 0.807

2.188 0.935 2.312 1.125 2.188 0.935 2.312 1.125

1.262 2.812 1.625 2.562 1.265 2.812 1.560 2.562 1.265 2.812 1.560

-

-

-

-

-

-

1.875 0.734 1.875 0.734 1.710 0.620

2.312 1.125 2.312 1.125

2.812 1.375 2.750 1.375 2.812 1.562 2.562 1.000

to Well Completion

RDS Resource

-

Design

- Premier Oil Pic

2.125 0.810

3.812 3.812 3.812 3.812 3.813 -

-

2.750 2.813 2.562

-

I SectionNo.

I Revision:

contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the infonnation disclosed within shall purpose whatsoever Including conceptual design, engineering, manufacturing or constnJdion without the express wrihen pennission of Premier Oil PLC.

This document

2.812

NIPPLE DHSV NIPPLE DHSV

NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV

,,--~-

A

not be reproduced

2.813 3.688

-

-

3.813

-

3.688

-

3.125 1.625 3.313

3.688 2.000 3.750

1.625

2.000 3.812 2.312 3.688 1.970 3.812 2.122 3.688 1.970 3.812

-

2.122 3.688

-

3.812 2.125 3.812 2.125 -

3.125 1.500

3.437 1.625

I Page No.: IVersion: 1 in whole or in part to any third party

68 any

OK

OTIS

MOD. FE/FXE

MOD. BE/BXE

Date 1/3/98

Prep. by :

IESL

Ref. This document contains purpose

whatsoever

CONFIDENTIAL Indueling conceptual


NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE

DHSV NIPPLE DHSV NIPPLE DHSV NIPPLE DHSV

1.875 0.620 1.875 0.750

-

1.875 0.620 -

2.188 0.810 2.313 1.000 2.125 0.810 2.188 0.810

2.750 1.380 2.813 1.380 2.562 1.000 2.750 1.500

2.313 1.120 2.125 0.310 2.188 0.810 2.313 1.000

2.813 1.500 2.562 1.000 2.750 1.380 2.813 1.380


Guidelines to Well Completion Design RDS Resource - Premier Oil Pic INFORMATION manufacturing

of Premier Oil PLC. This document and or c:onstnJdton without the express written

3.313 1.750

3.688 1.875 3.812 2.000 3.688 1.870 3.813 2.120

-

3.688 1.870 3.813 2.000 -


the information disdosed within shall not be reproduced in whole or in part to any third party any permission

of Premier

Oil PLC.

6.3

Special equipment

After the packer has been set and the completion string is run into the hole it has to seal - and optionally latch - into the packer bore. Polished bore receptacles provide a downhole sealing surface into which penetrators with a seal-stack can be stabbed. When thermal expansion and contraction during production or injection operations cause the seal-stack to slide along the polished bore it still maintains an effective seal.

Seals that are arranged on the outside of the tubing seal must be specified on the basis of:

. . .

Geometrical design Chemical composition Length of system

Geometrical Design The most common type of seal assembly is the chevron seal that comprises two stacks of V-section rings mounted in opposing directions. Differential pressure across the assembly deflects the chevrons outwards to fill the gap between seal bore and polished bore receptacle. Standard O-rings can be used in lower pressure differential environments. Chemical Composition The seal composition specified must be resistant to any H2S, C02 or other corrosive or aggressive materials in the wellbore. Seals are usually spaced along the length of the seal tube and separated by metal and/or Teflon back-up rings. See Section 4.4.2 for detailed seal selection criteria.

Length of seal system Once the seal assembly is located within the polished bore receptacle it will move in response to expansion or contraction of the tubing, so both must be of adequate

Date 1/3/98 Ref.

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This document contains CONFIDENTIAL and PROPRIETARY INFORMATION purpose whatsoever Induding conceptual design, engineering, manufaduring

-

of Premier Oil PLC. This document or construction without the express



and the information disclosed within shall not be reproduced in whole or In part to any third party any wrineo pennisslon of Premier Oil PLC.

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 10 and 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

Ref.

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T I



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This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and purpose whatsoever including conceptual design, engineering, manufacturing or ronstruction without the express written

the infonnation permission

of

disclosed within shall Premier

Oil PLC,

not be reproduced


to any third

party

any

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 special dielectric 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 selection of 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 Ref.

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I SectionNo.

I Revision:

This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the in(onnation disclosed within shall purpose whatsoever including conceptual design. engineering, manufacturing or oonstruction without the express written permission of Premier Oil PLC.

A

not be reproduced

I Page No.: 73 I Version: 1 in whole or in part

to any third party

any

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 Ref.

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I I

Guidelines

to Well Completion

RDS Resource

- Premier

Design Oil PIc

I SectionNo. T Revision: A

I Page No.: ., Version:

This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the information disclosed within shall not be reproduced in whole or in part purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express written permission of Premier Oil PLC.

74-

1

to any third party

any

f' I

Transformers

MotorController

Junction00x

Wellhead

Checkvalve

Powercable cableband Tubing

Flatcable

CentrifugalPump

SealSection

ESP completion design

Date 1/3/98

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This document

contains

CONFIDENTIAL

IESL

I I

and PROPRIETARY


of Premier

I Revision:

A

and the information disclosed within shall not be reproduced in whole without the express written permission of Premier Oil PLC.


purpose whatsoever including conceptual design. engineering, manufacturing or constNdion

I SectionNo.

IPage No.: 76 IVersion: 1 or in part to any third party

any

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

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Ref. This document contains CONFIDENTIAL purpose whatsoever including conceptual

Revision: A

document and the information disclosed within shall engineering, manufacturing or construction without the express wriUen permission of Premier Oil PLC.

and PROPRIETARY design,

SectionNo.

INFORMATION

of Premier

Oil PLC. This

not be reproduced

Page No.: 77 Version: 1 in whole or in part to any third

party any

BHP = BHP/Stage x No. of Stages x Specific Gravity of fluid to be pumped

I I I I I I

HEAD IN FEET

I I I I I I

OPER Al1NG

BRAKE HP

RANGE

35

PUMP EFF % 70

HE

CA

TV

30

60

50

25 PUMP ONLY EFRCIENCY

40

20 i

15

10

- .-

MOTOR LOAD BRAKE - HORSEPOWER . no - - - .- -

- --

..

-

1000

1500

30

.5

20

.25

10

-

5

500

.75

2000

2500

3000

3500

BARRELS PER DA Y

The next step is the choice of a seal section - usually dependant on the pump size, as each manufacturer will have a seal corresponding to the pump 0.0. Because the seal dissipates power in relation to the total dynamic head, the value of the pressure drop in the seal can be read from a table supplied by the pump manufacturer. Having calculated the power requirements for the motor and seal, the motor itself can now be selected. Subject to the same diameter limitations as the pump, a motor is chosen whose rating is slightly higher than the total power requirements to avoid operational overloading that would shorten its run-life. Most motors are available with

Date 1/3/98 Ref.

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higher voltage/lower current and lower voltage/higher current options. The decision between them is purely economic as high voltage requires a more expensive controller but cheaper cable, with the opposite requirement for the lower voltage option. The main factors in cable selection are cost - proportional to size

- and

voltage

drops caused by resistance losses which are inversely proportional to size. Other factors are the amperage and the space between tubing collars and casing. The cable voltage drop (from tables), modified for temperature, is then added to the motor voltage to give the total voltage needed at surface. Choosing the surface controls completes the pump selection operation. In more demanding environments such as high GOR, sour gas or very viscous

-

crude's, additional factors have to be considered in determining the optimum size and type of equipment for the life of the well. These factors will include the cable jacket and insulation and the erosion characteristics of the produced fluids.

Date 1/3/98 Ref.

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This document

INFORMATION

purpose


contains CONFIDENTIAL and PROPRIETARY whatsoever including conceptual design, engineering,

of Premier

Oil PLC. This document the express



and the information disclosed within shall not be reproduced in whole or in part \Wine" pennisslon of Premier Oil PLC.

to any third party

any

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

.

Minimum maintenancecosts

.

Design flexibility through the well life - from near-surface lifting initially, to neartotal-depth lifting at depletion

. .

Not affected by wellbore deviation

. .

Gas availability may be difficult

Long term reliable performance

Wide well spacing might restrict use of a central gas source

Date 1/3/98

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IPage No.:

IVersion:

This document contains CONFIDENTIAL and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the information disclosed within shall not be reproduced in whole or in part purpose whatsoever including conceptual design. engineering, manufacturing or construction without the express wrihen permission of Premier Oil PLC.

to any third

80

1 party any

.

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 kickoff 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

·

- fixed orifice

Continuous flow

- variable orifice ·

Intermittent flow

- minimum tubing-pressure control - maximum tubing-pressure control

Loading-type.

Date 1/3/98

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This document contains CONFIDENTIAL purpose whatsoever Induding conceptual

IESL

Gas-charged (bellows, piston or rubber sleeve chamber)

I I



-



INFORMATION of Premier Oil PLC. This document and the infoonatlon disctosed within shall manufacturing or construction without the express written permission of Premier Oil PLC.

not be reproduced

in whole


any

....---

·

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 bellowsvalves 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 precharged 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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Section No.

Page No.: 82

Revision:A

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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 3000 psi differential pressure (Camco, Macco - with valve travel stop)

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The Macco gas-charged bellows design is used only in casing-pressure operated installations. Both the Guiberson and Harold Brown valves have a field inspection facility.

As a spring provides the loading force in the Macco valve for fluid weight applications there is no charge pressure. The spring-loaded valve, which supersedes their previous gas-charged model, eliminates the need for a temperature compensation in the installation design. The USI fluid-operated valve is a conversion of their Balance Pressure Valve that has tubing rather than casing pressure acting on the bellows area. This allows the casing pressure to be completely balanced so that valve operation is controlled only by tubing pressure build-up. Spring-loaded differential intermittent valve In all models casing pressure acts on a piston having the same hydraulic area as the stem on which tubing pressure acts. The spring load holds the valve open until it is overcome by increasing differential pressure across the small inlet choke. On all other types of valve the loading force tends to hold the valve closed until the differential between casing and tubing pressure becomes less than the spring setting and the valve opens.

Combination spring and gas-charged bellows intermittent valve A combination of spring and gas-charged bellows provides the loading force in this type of valve. Although the spring setting is usually about 75 psi this can vary between different valve series, so it is important that the user checks and records it precisely. The valve pressure can be field-adjusted with the calibrated spring and has a reduced temperature factor because the spring provides part of the loading force. Although the spring will keep the valve closed in case of bellows failure, it cannot be opened by casing pressure. Continuous flow valves

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All the preceding intermittent-flow valves can be modified for use as continuous flow valves.

Operating characteristics Area factors The bellows-type valve has three hydraulic areas on which pressure can act

- the

bellows (Ab). the stem (As) and the port (Ap). Although various manufacturers use different conventions for their operating equations. the following has been adopted for convenience:

Bellows factor:

Fb = Abl (Ab

Port factor:

Fp = Api (Ab - Ap)

Stem factor:

Fs = AsI (Ab - Ap)

- Ap)

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). Manufacturer catalogues list the standard springs available for their various valve types.

Nominal setting pressure

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A bellows valve is usually charged with nitrogen for workshop testing, but because the actual bellows pressure cannot be calibrated without being affected, this must be done relative to an external Nominal Setting Pressure.

The Nominal Setting Pressure (Pn) is the external pressure at which the valve opens with atmospheric pressure under the valve stem (P, = 0) at 60°F.

Back pressure effect

The back pressure effect is the difference between the normal setting pressure Pn and the pressure Po at which the valve opens if the

-

pressure under the stem is P, instead of atmospheric.

An increase or decrease in pressure under the stem is therefore only partly reflected in the pressure required to open the valve. The factor Fp is frequently referred to as the "back pressure factor" although it is by definition equal to the port factor. Thus, the opening pressure of a Garrett OCF type valve decreases by 75 psi when the back pressure is increased from zero to 450 psig.

Valve spread

The valve spread is the difference between the injection pressure required to open the valve and the injection pressure at which it closes (PiC)'

The pressure under the stem is not zero under downhole operating conditions, so that the valve spread depends not only on the valve characteristics (Fp, Fband Pn) but also on the flowstring pressure and temperature. Since the gas column gradient can be assumed to be the same for Pioand Pic,the valve spread is often defined as the difference in surface injection pressure on

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opening and closing the valve. This determines to a large extent the amount of gas injected per cycle during intermittent gas lift operations.

Gas lift valve classification The following classification of gas lift valves is based on their main operating characteristics. It depends on the different possible combinations of the injection pressure Pi and/or the flowstring pressure Pf that can act on the Ap and (Ab - Ap) areas in the open and closed positions. A similar distinction can be made for retrievable, spring loaded and casing flow type gas lift valves.

Pressure Operated Valves The opening

and closing characteristics

of this group of valves are governed

primarily by the injection pressure since this acts on the (Ab - Ap) area in both open and closed positions. >

Valve opening in this group is also partly governed by the flowstring pressure, which acts under the stem in the closed position. Whether pressure (Pi or Pf) acts on the stem in the open position depends on where the gas flow is being controlled. a) In Continuous Flow Valves or Constant Flow Valves, the gas is controlled by nozzles upstream from the stem chamber so that flowstring pressure acts on the stem in the open position. The closing characteristic of this type of valve is partly dependent on the fluid back pressure.

b) In Intermittent Flow Valves the gas is controlled downstream from the stem chamber so that the valve closure is independent of flowstring pressure. The same principles apply to Large Port Valves that have a sealed chamber and a bore-hole through the thick part of the stem.

Balanced Pressure Operated Valves

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Because of the construction of the bellows sealed chamber, injection pressure acts on the stem as well as the bellows in both open and closed positions - flowstring back pressure has no influence on the way it operates. This also applies to valves, which have a resilient element. Opening and closure in this group of valves is wholly governed by gas injection pressure. Fluid Operated Valves The opening and closing characteristics of this group of valves are governed mainly by fluid back pressure as this acts on the area (Ab - Ap) in both open and closed positions.

a) Conventional Fluid Operated Valves are standard intermittent pressure operated valves in which the direction of gas flow has been reversed. The

...

injection pressure thus acts on the stem in the closed position with the opening characteristic partly dependent on Pi. b) Intermittent Fluid Operated Valves. Because injection pressure acts on the stem in the open position its closing characteristic is partly dependent on Pt. Partly Balanced valves also belong to this group, the name referring to the influence that injection pressure can also have on the opening characteristic where the port area is smaller than the stem area. c) Balanced Fluid Operated Valves. Since the flowstring pressure acts on the stem as well as the bellows in both open and closed positions, the operating characteristics are wholly governed by flowstring pressure and independent of injection pressure. While the opening characteristic can be made dependent on injection pressure if the port size is smaller than standard, the classification is unchanged because the closing characteristic is not affected, unlike the group above.

Differential Valves

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Page No.: 88 Version: 1 in whole or In part to any third party any

'\

a) Spring Type. Spring tension keeps the valve open until overcome by the pressure differential created by gas flow through nozzles that are upstream from

the

stem

chamber.

Consequently,

operating

characteristics

are

independent of the injection and flowstring pressure values.

b) Bellows Type. The dome chamber has two check valves working in opposite directions, on which two small springs can be set for the pressure differential required to open them. This allows dome pressure to be varied without pulling the valve by increasing or decreasing the injection pressure to a fixed differential above or below the dome pressure. Thus, valve response to the combination of injection and flowstring pressure can be changed by manipulating the surface injection pressure. When set, opening and closure depend on the pressure differential across the valve

.....

Gas lift mandrels Also referred to as side pocket mandrels, they are the housing in which the gas lift valves are installed. The mandrels are installed in the tubing string nipples when running in the completion, but if artificial lift is not required initially, the valves can be run in later on wireline. Mandrels are often used to carrY valves for such other functions as chemical or waterflood injection and fluid circulation.

7.1.3

Coiled Tubing completions

Coiled tubing (CT) is one of the newer technologies available, but so far has been used only occasionally in completion applications for both new and existing wells. It was first used to overcome water loading in gas wells by installing a CT string inside the production tubing to reduce the flow area. This increased the gas velocity to a level at which it carried the water to surface, so avoiding build-up of a water column. Also known as a velocity string, this successful technique has led the way into other more demanding completion applications. Still awaiting wide acceptance, this type of completion has the following advantages and limitations:

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Advantages

. . .

Lower cost for certain applications Rapid installation, reducing rig time and logistics Allows fast and safe live well operations without risking reservoir integrity through killing the well

.

Few connections give faster deployment and reduced risk of tubing leaks

.

Compatible with artificial lift methods and equipment

Limitations

-

.

Requires operators with specialised skills

.

Equipment costs in most countries are higher than conventional jointed tubing units

.

Maximum 00

3.5", while string length and metallurgy also to be

considered

.

Longevity and field performance of CT completion equipment yet to be established

.

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Not yet suitable for highly corrosive conditions requiring CRA materials

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to any third party

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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.

Gas lift

-

Primary production strings

·

Velocity strings

·

Electric submersible pumps

·

Single point

·

Multiple external

·

Multiple internal (spoolable)

Well bore isolation.

Production liner

Sand control

Gravel pack

·

Injectionstrings ·

Gas andwater injection

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

Disadvantages

·

Quick to run, lower cost

·

Feasibility proven with main technical difficulties overcome

·

Live well completion possible

·

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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Page No.: 91 Version: 1 or In part 10 any third

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,

a velocity string is most effective where a steady reservoir decline is followed by either a sudden increase in produced liquids, or a sudden halt in production.

Advantages

.

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

threaded,

conditions

and

configurations

from

simple

to fully flanged high pressure for sour service

Disadvantages

Multi-diameter CT string requires specialised equipment

·

and

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 .

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Flow control equipment, nipples and related components

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INFORMATION

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engineering.

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construction without the express written

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·

Packers and anchor tools for isolating or anchoring the CT completion

-

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93

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Electric submersible pumps (ESP)

CT provides an ideal ESP-conveyance method and production conduit. While the same factors apply as in a conventional system - tensile strength, load weights, shut-in loads etc - the maximum ESP motor torque must also be considered.

Advantages

· Less time to run in and retrieve ESPs · Costs may be lower

Disadvantages.

Relatively smalllD may increase friction pressure and back pressure ·

Insufficient data to compare life expectancy of jointed pipe

-

and CT

Gas lift production The introduction of larger diameter CT has broadened the utility and applications for gas lift coiled completions.

Single point injection

.

Straight forward CT completion arrangement with the configuration similar to a velocity string. Either flow path can be used for production.

Multi-point external valves Usually assembled with clamp-on gas lift mandrels, these are compatible with annular or tubing production flow paths. The installation generally uses a split housing to support the gas lift assembly which is completed by drilling a hole in the CT. Some form of "work window" is necessary for fitting the gas lift valves below the CT injector head and pressure control equipment..

Advantages

·

Disadvantages ·

Quick and economical installation with minimum equipment External valves not wireline retrievable so whole completion must be retrieved for valve replacement or servicing

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[



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INFORMATION manufaduring

~ Section No. Revision: A

of Premier Oil PLC. This document and the information disclosed within shall or conslrucUon

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wriUen

pennission

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Oil PLC.

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J Page No.: 94 Version: 1 in whole or in part

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.

Valvescannotbe blankedto allow pumpingof 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-offto 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 ·

7.2

Full downhole safety facilities must be provided

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.

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95

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Sand production is a rather complex mechanism that is strongly influenced by the field stresses and production strategy. Because the methodology and equipment for identifying the sanding potential of a particular reservoir is still considered more art than science, only simplified models and local expertise are available to address the problem. Few theoretical models and empirical techniques have been developed over the years.

The sequential flow test is one of the older but more useful techniques because it exposes the well to realistic production conditions. Initially used as a prediction tool it is now mainly used to calibrate the estimates made by the analytical models. However, it is of limited value because it cannot reflect the changes in field stress

-

during reservoir depletion. The combined modulus technique, developed by Mobil in the 70s, was applied successfully in the US Gulf Coast. Density and sonic logs were used to compute the elastic modulus of the rock and establish a threshold value of 3 x 106Psi above which a formation was unlikely to produce sand.

The Mechanical Properties Log (MECPRO) was developed by Schlumberger to predict the maximum allowable drawdown pressure on the rock before the onset of sand production. As the model worked better for hydraulic fracturing than for predicting sand production it was of limited application, but has since been further developed into ROCPRO and, most recently, IMPACT. Unfortunately, both these models rely on unrealistic assumptions that are not representative of actual field conditions. Because IMPACT can use many of the existing models such as Bratli & Risnes and Coates & Denoo, it could be useful where they can predict sand production onset with any certainty. Morita's Model and the work by Kessler, Santarelli & San Filipo, developed algorithms that predict the cavity stability and sand production potential of perforations using robust engineering tools such as Morita's finite element

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analysis. Kessler et al developed a semi-empirical approach based on a large amount of successfully calibrated field data from the Mediterranean and North Sea.

A comprehensive analysis of sand production potential requires a systematic approach to the most important factors:

.

. . . . . .

--

Date 1/3/98 Ref.

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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

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7.2.2

Gravel pack completions

In a gravel pack, the annulus between the wellbore and a base perforated pipe with its wire-wrapped screen is filled with gravel sized to prevent sand from the well passing through the pack. The gravel is either packed into the screen at manufacture (pre-pack) or subsequently placed downhole in the annulus between the screen and the wellbore. Pre-packed screens have the advantage of not relying on successfully placing the slurried gravel in the annulus. However, the screen may be damaged when it is being run in and must also be protected from plugging by fines during the installation. The main advantages and limitations of gravel packing are:

--

Advantages

.

Treatment does not depend on chemical reactions

.

Productivity impairment is usually small

. .

Especially useful for controlling sand in long productive intervals Easier to apply in composite sand

Disadvantages

.

Complicates workovers

.

Screen damage from erosion and corrosion is a major concern

. .

Can be difficult to use in deviated and horizontal wells Flow control and isolation is more complicated.

The gravel size is an important factor in achieving a successful gravel pack. Much work has been done to evaluate the effect of different gravel sizes on formation sand of varying grain size, towards preventing or restricting sand invasion of the pack and consequent impairment of production. The current method of sizing gravel is based on work by Saucier who recommends that the median gravel size should be six times the average size of sand grain. While there would be no major sand invasion with a smaller ratio, the pack permeability would be significantly reduced. Although permeability would remain high with a larger ratio, sand would

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CONFIDENTIAL

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purpose whatsoever includina conceptual design. engineering, manufacturing or construction without

This


document and the Infonnation disclosed within

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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. Gravel placement 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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party any

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.

--

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7.2.3.

Slotted liners and screens

Slotted liners - one of the earliest methods of sand control

- are

tubing sections,

which have a series of slots cut into the walls. The slot width is designed to initiate inter-particle bridging across the slot and was originally considered should be twice the diameter of the 10 percentile sand grains. However, it is now suggested more conservatively that they should only be about the same size.

Wire-wrapped screens have a base pipe with slots or holes around the circumference that is either single-wire wrapped or is surrounded by cylindrical sieves of various mesh sizes. This allows fluid flow into the 10 but prevents sand passing into the production string. A V-shaped or 'keystone profile' wire minimises the plugging that often occurs with standard-profile wire. The largest possible 00 sand screens are used to fill the surrounding annular space and prevent the collapse of unconsolidated reservoir sections.

A disadvantage of the system is the difficulty of selecting screens to maximise the flow area while avoiding loss of productivity due to formation collapse. However, these problems are now being reduced by recent improvements in screen design which include improved wire spacing tolerances, new materials such as 'sintered' metal tubing and pre-packed screens. Screen effectiveness has also been improved by the newly developed expandable screen and by better quality control. There are two main criteria for designing screen-completions:

. .

Hydraulic performance of produced fluids through the base pipe The effect on production of plugging in the screen or pre-pack

The hydraulic performance of the produced fluids through the base pipe only becomes important when flow rates are high or the screen size is less than 2-3/8". This factor plays a major role in high rate horizontal wells in the North Sea, where

Date 1/3/98

Ref. This

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This document

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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 or I

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 Ref.

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Guidelines

to Well Completion

RDS Resource

ThisdocumentcontainsCONFIDENTIAL purpose whatsoever

IESL

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Design

Oil Pic

Section No.

Page No.: 102+ I DJ

Revision:A

Version: 1

and PROPRIETARY INFORMATION of Premier Oil PLC. This document and the infonnation disclosed within shall includina conceptual design. engineering, manufacturing or construction without the express wrinen Dermission of Premier Oil PLC.

not be reproduced

in whole


any

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.

Advantages

.

in

Original production packer and completion equipment remain place during the treatment reducing costs and logistic

problems

.

-.-<

Reduced risk of damage to the formation through shorter exposure to potentially damaging fluids

Date 1/3/98

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Guidelines

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Ref. and PROPRIETARY design. engineering,

-


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8

Operational aspects of well completions

There are many aspects to the installation operations fo~ a well completion, but the primary objective is to ensure that the system will perform as designed under actual production conditions. This section reviews some of the important factors in preparing, running and retrieving a completion string. Also included are general procedures for some of the more common well intervention operations using wireline and coiled tubing.

8.1

Installing and retrieving the completion string

The preliminary phase of a completion installation is concerned with equipment

-

and logistics preparation. With this completed, the first site operation is handover of the well from drilling (or production) to the completions team. However, there is no industry uniformity to the organisation of completion installations as every company takes an individual approach

- with

some completion operation carried

out by drilling personnel.

8.2

Well handover - general procedures

- NO INPUT 8.2.1

Component testing

- NO INPUT

Date 113/98 Ref.

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SUPPLIED

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Section No.


This document contains CONFIDENTIAL and PROPRIETARY INFORMATION purpose whatsoever Induding oonceptual design. engineering, manufaduring


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and the information

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Revision: A


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8.3

Wireline operations

Well maintenance, remedial work, control and safety functions are among the many operations performed with wireline services that save money and time if carried out efficiently and safely. However, wireline applicability can be restricted by such factors as corrosion, sand and scale, well deviation and equipment. The two main types of wireline operation are:

. .

Solid line (also known as slick line or solid wire)

.

Electric wireline

Multi-strand (braided line or wire line)

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

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H2S conditions 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 Ref. 1/3/98 This document

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IESL

~



RDS Resource INFORMATION

manufaduring

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- Premier Oil PIc

Oil PLC. This document and the express written


~ Section Revision:No. A

the infonnatlon disclosed within shall not be reproduced pennission of Premier Oil PLC.

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element. Better sealing is obtained with the grease injector head that extrudes very high viscosity grease around the line as it passes through close-fitting flow tubes. Although the assembly is designed to hold up to 5,000 psi, it is difficult to achieve 100% sealing. The equipment required to supply pressurised grease includes:

. . . . . . . .

....

Grease injector head assembly High pressure grease pump Grease reservoir Compressor Hoses Wiper box Sheave Crane

Lubricator The lubricator is a tube with quick connections at each end that enables tools to be run into and withdrawn from a pressurised wellbore. Threaded connections can be used for wellhead pressures up to 5,000 psi, but above that level the quick connections must be welded in position, then x-rayed and pressure tested before use. Lubricator pressure limits are tabulated below.

Lubricator test and working pressures

Working Pressure

[psi]

Test Pressure [psi]

3000

4500

5000

7500

10000

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

Ref. Date 1/3/98

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i

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and any items being recovered. Lubricators should be x-rayed, magnifluxed for cracks and visually inspected at regular intervals, with a particular check of the internal walls for wire-tracking

damage that could reduce their strength

significantly. HzS-resistant lubricators are required to be used if a well has more than 10 ppm HzS. Quick unions The connections used to assemble the wireline service lubricator and associated equipment are known as quick unions. They are designed to be made up only by hand, so collar and union should never be loosened with pipe wrench, hammer or chain tongs. If a quick unio!l cannot be hand-turned easily, it must be assumed that there is still internal pressure that will have to be released using all appropriate precautions. The box end of the union has an external ACME thread and accepts a pin with O-ring seal whose internally threaded collar is then hand-made up to the box when the pin has shouldered out. As the O-ring forms the pressure-retaining seal, it must be carefully inspected for damage before making up the union.

Blow-out pre venters (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 BOP when the BHA is stuck in the hole

.

permit the wire to be stripped through closed rams in emergency

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When the rams close they seal against the wire either mechanically or hydraulically. The blind rams used for slick line (0.092", 0.105/0.108") and braided line (3/16",1/4", conductor cable) are: Slick line.

Rams have rubber inserts on the sealing faces to allow sealing with or without wire across them

Braided line

·

Rams have a semi-circular groove in the seals matching the diameter

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

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This document

I I


-

I SectionNo. T Revision : A

document and the information disclosed within shall induding conceptual design, engineering, manufacturing or construction without the express written permission of Premier Oil PLC.

contains

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IESL

CONFIDENTIAL

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Weight indicator A Martin Decker is the most common of the weight indicators. These show tension changes resulting from variation of fluid level or density, prevent overloading of the wireline and indicate jarring action as well as the position of the downhole equipment. The sensor is attached to the tree and a heavy duty hose transmits the hydraulic signal to the fluid-filled gauge. System accuracy depends on precisely locating the sensor so that the line is at right angles to the hay pulley. Hay pulley 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 Ref.

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I Page No.: I Version: or In part

111

1


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.

. Date 1/3/98 Ref.

The system to be pressure tested to the levels previously used.

IPrep. by:

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This document

.

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

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CONFIDENTIAL

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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 by manufacturer 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 by jarring

Pack-offto be pressuretestedto the levelspecifiedby manufacturer,but not to exceed the DHSV pressure test

.

Overpull of 400 Ib to be applied to confirm correct landing then release pins to be sheared

Date

Ref.

1/3198

IPrep. by : I

IESL

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RDS Resource

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Oil PIc

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I Revision:

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No.:

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.

On pulling out of hole, tell-tale spring on the running tool to be confirmed as in the correct position

.

Procedures to be repeated to set the prong in the pack-off or plug body Downhole assembly to be pressure tested by slowly bleeding off wellhead pressure at the test separator. Wellhead pressure to be less than 1 bar for a valid test. After any pressure increase over 15 minute period indicating a faulty prong, faulty pack-off or both, the prong to be re-run first then followed by pack-off. Pressure from above to be applied by inhibited seawater or nitrogen.

---

Date 1/3/98

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X4. Electric line - FOLLOWING IMPORTED FROM ABOVE -

X.4.1 Rig Up Procedure

(with 200 ft running speed max)

.

.

Rig personnel must be made fully aware of the safety aspects of operations by: 1

Safety meetings held with both shifts (repeated after any crew changes)

2

Erecting safety barriers

3

Ensuring familiarity with and adherence to emergency procedures

4

Strictly conforming to permit-to-work procedures.

Prior attention (pre-rig-up) should be given to: 1

Valid certification for all equipment

2

BOPs have correctly sized rams

3

Sufficient wire on the unit

.

Wireline engineer to confirm that equipment is ready for rigging up

.

Great care should be taken with operations on the BOP deck, especially when overhead cranes are being used

.

All equipment to be securely tied down

Pressure testing

.

Riser elements between production tree and wireline BOPs to be pressure tested in place

.

Wireline BOPs to be pressure tested with the test rod, taking precautions to avoid the rod being blown out of the well or falling downhole. Test pressure shall be 120% of expected wellhead pressure and conform to local regulations. Pressure testing is carried out prior to the first wireline rund only.

.

Wireline tools to be made up and zeroed appropriately

.

After rigging up the wireline pressure control equipment with the wireline, the tools are to be pulled into the top of the riser. All hydraulic hoses to be connected and wireline pressure equipment to be function tested.

Date 1/3/98 Ref.

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This document contains CONFIDENTIAL and PROPRIETARY purpose whatsoever including conceptual design, engineering.

Guidelines to Well Completion Design RDS Resource - Premier Oil PIc INFORMATION

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This document

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manufacturing or construction without the express written permission

disclosed

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SectionNo.

Page No.:

Revision: A

Version:

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shall not be reproduced

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116

1

to any third party

any

.

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: ·

Date 1/3/98

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.

·

Guns are below 1,000 ft on RIH.

·

Firing the guns.

·

Guns are above 1,000 ft on POOH.

·

Disarming guns.

Prior to arming the guns all explosive safety guidelines must be adhered to. If any procedure can not be followed for whatever reason, operations must be suspended

. .

Date 1/3/98

No explosives to be in the well during pressure testing of surface equipment CCl reference log to be made available to the wireline engineer

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129842114 Well Completion Design Guideli[1]

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