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& Well Control Training Centre

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ABERDEEN DRILLING SCHOOLS

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WELL INTERVENTION PRESSURE CONTROL

Written and Published by Aberdeen Drilling Schools Ltd.

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FOREWORD Well pressure control is the most critical consideration in the planning and performing any well servicing operation. The awareness of well pressure control in the prevention of injury to personnel, harm to the environment and potential loss of facilities, must be fully appreciated by planning engineers and well site personnel. This appreciation must include a sound knowledge of legislative requirements, completion equipment, pressure control equipment and operating practices and procedures. ‘Well Intervention’ and ‘Workover’ are commonly used terms to describe servicing operations on oil and gas wells and which have, in the past, had many different interpretations. However, in general,‘Workover’ describes well service operations on dead wells in which the formation pressure is controlled with hydrostatic pressure. Workover operations are carried out by a drilling rig, workover rig or Hydraulic Workover Unit (HWO) where the Xmas tree is removed from the wellhead and replaced by blow out preventor (BOP) equipment.‘Well Intervention’ is a term used to describe ‘through-tree’ live well operations during which the well pressure is contained with pressure control equipment.Well Interventions are generally conducted by wireline, coiled tubing or snubbing methods. Snubbing operations are now usually conducted with HWO units. This ADS course is designed to train personnel in Well Intervention Pressure Control. Well pressure control equipment used by wireline, coiled tubing and snubbing units is so termed as it must control well pressure during live well intervention operations. It significantly differs from BOP systems used on dead well workovers. As most well servicing is now carried out by these live well intervention methods, it is essential that these are fully addressed during this course. The term Well Control specifically applicable to drilling or dead well workover operations are not addressed in this manual. However, it is necessary to review Production Well Kill Techniques and have a thorough understanding of Pressure Basics to minimise risks involved when placing fluids in the well, whether it is to provide a barrier or when performing a well intervention activity. To have an understanding of well operations conducted by live well intervention methods and the associated pressure control equipment, it is first necessary to have, or obtain, a basic knowledge of completion designs, completion equipment, practices, well service methods and their applications. An overview of these activities is given in the manual with a multitude of exercises the student can work through to review their knowledge. Training in well intervention well pressure control is an essential part in ensuring the competence of personnel involved in the planning and carrying out of live well servicing operations.The Aberdeen Drilling Schools Ltd. WELL INTERVENTION PRESSURE CONTROL TRAINING COURSE and course materials intend to provide this essential knowledge in order to help delegates to obtain an IWCF (International Well Control Forum) certificate in Well Intervention Pressure Control.

© ABERDEEN DRILLING SCHOOLS 2001

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IWCF WELL INTERVENTION PRESSURE CONTROL

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AIMS AND OBJECTIVES The overall aim of the course is to provide a delegate with the theoretical skills essential in applying well pressure control during well intervention and servicing operations with the objective of improving the individuals knowledge and level of competence. AIMS The individual aims are to: • Provide an appreciation of completion types, equipment, equipment functions and practices as recognised by the industry. • Establish an increased awareness of well intervention/servicing well control equipment, methods and practices. • Furnish a student with a knowledge of legislative guidelines and standards. • Provide an awareness of how to discern well pressure control problems and apply solutions. OBJECTIVES The individual objectives are to assist the delegate to: • Improve his/her competence in well intervention pressure control. • Obtain IWCF certification. • Identify well pressure control problems from available well data i.e. pressure, volume and flow characteristic. • Identify solutions to various well pressure control problems. • Understand legislative guidelines and standards. • Determine if pressure control equipment is fit for purpose.


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OVERVIEW OF COMPLETIONS

1.1

INTRODUCTION

1.2

CLASSIFICATION OF COMPLETIONS

1.3

COMPLETION EQUIPMENT

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2.

WELL CONTROL METHODS

2.1

GENERAL

2.2

BARRIER THEORY

2.3


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REASONS FOR WELL INTERVENTION

3.1

GENERAL

3.2

TUBING BLOCKING

3.3

CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION

3.4

MECHANICAL FAILURE

3.5

STIMULATION OF LOW PRODUCTIVITY WELLS

3.6

PARTIALLY DEPLETED RESERVOIRS

3.7

SAND CONTROL

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WELL INTERVENTION SERVICES

4.1

GENERAL

4.2

SNUBBING / HYDRAULIC WORKOVER UNITS (HWO)

4.3

COILED TUBING UNITS

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PREVENTION OF FORMATION DAMAGE

5.1

FORMATION DAMAGE

5.2

DAMAGE PREVENTION

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6.

PRESSURE BASICS

6.1

FUNDAMENTALS OF FLUIDS AND PRESSURE

6.2

FORMATION PRESSURE

6.3

FORMATION FRACTURE PRESSURE

6.4

FORMATION INTEGRITY TESTS

6.5

MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP

6.6

CIRCULATING PRESSURE LOSSES

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7.

PRODUCTION WELL KILL PROCEDURES

7.1

WELL PREPARTATION

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8.

WELL CONTROL EQUIPMENT

8.1

GENERAL

8.2

SNUBBING OPERATIONS

8.3

WIRELINE OPERATIONS

8.4

COILED TUBING OPERATIONS

8.5

SUBSEA WELL INTERVENTIONS

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1.1

INTRODUCTION

1.2

CLASSIFICATION OF COMPLETIONS

1.3

COMPLETION EQUIPMENT

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1.1 INTRODUCTION In combination with the disciplines of geology, geophysics, and geochemistry, the usual purpose of drilling a well is to establish the subsurface location of hydrocarbon reservoirs.The term ‘completion’ is derived from the operation to complete a well for production after it has been successfully drilled. Dependent upon the reason for a well to be drilled (i.e. wild cat exploration, appraisal or production) and the results of logging and/or well test results, the well will then be: i. ii iii.

Plugged and abandoned (as it has no further use i.e. a duster). Suspended as a future or possible production well. Completed as a production well.

In the early days, if the well was to be ‘completed’ (as in iii) above, the hardware installed, i.e. packer, tubing, Xmas tree and other accessories, was termed the ‘completion’.The purpose of completing a well is to produce hydrocarbons to surface production facilities. Commercial reasons demand that this is achieved in an efficient, cost effective and safe manner throughout the producing life of the well. Completing a well consists of a series of operations that are necessary to enable a well to produce (and to sustain the production of) hydrocarbons following the installation and cementing of the casing. Well completion operations include: • • • • • • •

Perforating. Sand control. Production packer installation. Tubing (completion) string / tubing hanger installation. Downhole safety valve installation. Xmas tree installation. Bringing the well onto production.

Well servicing methods must be considered as a fundamental element in the planning and completion design process. For example, early measurement of formation parameters (porosity, permeability) may indicate the need to stimulate (fracturing, acidising) a well to enhance the production rate. An appropriate completion design must cater for these and any future possible well servicing operations, both planned and unplanned. Similarly, subsea completions will necessitate operations such as flowline and surface safety valve installations. It should be emphasised here that such completion operations are not independent and the engineer needs to understand the basics in every area to be most effective in producing a completion design to cater for all contingencies. An engineer, when considering completion options, should adopt a realistic approach to the overall project economics i.e. the cost of the equipment, service life, type of servicing and respective rig time etc. In general, the ideal completion is the lowest cost completion which will meet the demands placed on it during its producing life. © ABERDEEN DRILLING SCHOOLS 2002

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IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS

In reality, many unforeseen problems can arise due to the initial available data being deficient and it is commonly seen that subsequent completion designs on a field are developed as the data base increases. 1.2

CLASSIFICATION OF COMPLETIONS Even though different types of wells present distinct design and installation problems for the engineer, most completion types are simply variations on a few basic designs, therefore the equipment installed is generally similar. Completions may be classified with respect to the following. Reservoir/Wellbore Interface In the absence of formation damage, this determines the rate at which well fluid is transferred from the formation to the wellbore. The types of completion involved here are: • • • •

Open hole completions. Uncemented liner completions. Perforated liner completions. Perforated casing.

Mode of Production This relates to the way well fluid is transferred from the wellbore at the formation depth to the surface, i.e.: • •

Flowing. Artificial lift.

Number of Zones Completed This effectively governs the volume of hydrocarbons recoverable from a single bore hole: • •

Single. Multiple.

Figure 1.1 indicates the types of completions and various methods used to produce well fluid to surface.

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Interval segregation Concentric String Multiple Strings Twin String, Dual Completion

Single Zone

Single String, Dual Completion

Interval Co-Mingling Standard

Artificial Lift

Mode of Production

Plunger Lift Gas Lift Hydraulic Pump

HighPressure Temporary, simple, low cost Tubingless

Internal Gravel Pack Standard

Uncemented Liner

Perforated Liner

Perforated Casing

High Rate Liner

External Gravel Pack Pre Packed Screen Wire Wrapped Screen Slotted Pipe

Open Hole

Vertical/ Deviated Wells

Flowing (Single String)

Rod

Horizontal Wells (See figure 1.13)

Interface Between Wellbore and Reservoir

COMPLETIONS

Electric Submersible Pump

Figure 1.1- Classification of Completions for Vertical or Deviated Wells


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1.2.1 Classification by Reservoir/Wellbore Interface Open Hole Completions In this type of completion the casing is set in place and cemented above the productive formation(s). Further drilling extends the wellbore into the reservoir(s) and the extended hole is not cased; See Figure 1.2. This completion method is used where it is desirable to expose all zones to the wellbore. Producing formations must be of firm rock which will remain in place during production. Open hole completions are also referred to as ‘barefoot’ completions. Advantages of Open Hole Completions are: • • • • • • •

The entire pay zone is open to the wellbore. Perforating cost is eliminated. Log interpretation is not critical since the entire interval is open to flow. Maximum wellbore diameter is opposite the pay zone(s), hence gives reduced drawdown. The well can easily be deepened. Is easily converted to liner or perforated casing completion. Minimal formation damage is caused by cement.

Cement

Cement Production Casing

Formation

Formation

Figure 1.2 - Open Hole Completion Schematic

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Disadvantages of Open Hole Completions are: • • • • • •

The formation may be damaged during the drilling process. Excessive gas or water production is difficult to control because the entire interval is open to flow. The casing may need to be set before the pay zone(s) are drilled and logged. Separate zones within the completion cannot be selectively fractured or acidised. Requires frequent clean out if producing formations are not consolidated. May be difficult to kill if installed in a horizontal well for well servicing or workover or abandoned purposes.

Limitation of Open Hole Completions are: • •

Unsuitable to produce pay zones with incompatible fluid properties and pressures. Mainly limited to Limestone formations.

Uncemented Liner Completions In some formations hydrocarbons exist in regions where the rock particles are not bonded together and sand will move towards the wellbore as well fluids are produced, this formation is usually referred to as being ‘Unconsolidated’. The use of uncemented liners (slotted or screened) act as a strainer stopping the flow of sand. Liners are hung off from the foot of the production casing and usually sealed off within it to direct any well flow through the liner bore. Various examples of uncemented liner operations implementing sand control are as follows: Advantages of Uncemented Liner Completions are: • • • • • •

Entire pay zone open to the wellbore. No perforating cost. Log interpretation is not critical. Adaptable to special sand control methods. No clean out problems. Wire wrapped screens can be placed later.

Disadvantages of Uncemented Liner Completions are: • • • •

The formation may be damaged during the drilling process. Excessive water or gas is difficult to control. Casing is set before pay zones are drilled and logged. Selective stimulation is not possible.


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Various examples of uncemented liner operations implementing sand control are as follows: a) Slotted Liner Slot widths depend on the size of the sand grains in the formation and are typically 0.01 ins. - 0.04 ins. (0.254 - 1.016 mm) wide; See Figure 1.3a b) Wire Wrapped Screens Liner is drilled with 3/8 ins - 1/2 ins. (9.53 - 12.7 mm) holes along its length and then lightly wrapped with a special V-shaped wire; See Figure 1.3b Uncemented liner completions are not used very often since: • •

Sand movement into the wellbore causes permeability (flow rate) impairment. Screen erosion can occur at high production rates.

These problems may be overcome by filling the annulus between the open hole and screen with graded coarse sand, i.e. gravel packing, which acts to support the open hole section as well as prevent formation sand movement. c) External Gravel Pack The open hole is enlarged to about twice its diameter and a liner is run. Correctly sized gravel is placed between the outside of the screen and the formation by using special gravel pack running equipment; See Figure 1.3c d) Pre-packed Screen A Pre-packed screen is constructed of an outer and inner wrapped screens with resin coated gravel placed between the screens. This gives a performance better than a wire wrapped screen but less that an open gravel pack. These are used when there may be difficulty in installing a gravel pack.

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Cement Liner Hanger

Production Casing

Slotted Liner

Unconsolidated Sand Formation

Unconsolidated Sand Formation

a) Slotted Pipe

Slotted Liner

Slotted Liner

Graded Gravel

b) Wire Wrapped Screen

c) External Gravel Pack

Resin Coated Gravel

d) Pre-packed Screen

Figure 1.3 - Uncemented Liner Completion Schematics


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Perforated Cemented Liner Completions In perforated cemented liner completions, the casing is set above the producing zone(s) and the pay section(s) drilled. Liner casing is then cemented in place which is subsequently punctured (perforated) by bullet-shaped explosive charges. These perforations are designed to penetrate any impaired regions around the original wellbore to provide an unobstructed channel to the undamaged formation. By using various depth measuring devices (i.e. casing collar locator, CCL) various sections of pay zone can be perforated accurately (excluding unproductive regions), avoiding the production of undesirable fluids (gas or water), or production from unconsolidated sections that might produce sand. The various methods of completing a well using perforated cemented liner operations are: • •

Single, See Figure 1.4, or multiple pay zones. Single or multiple pay sections.

Cement Production Casing Liner Cement

Formation

Liner Hanger Perforations

Formation

Figure 1.4- Perforated Cemented Liner Schematic

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Perforated Cemented Casing Completions In a perforated cemented casing completion, sometimes referred to as the ‘set through’ completion, the hole is drilled through the formation(s) of interest and production casing is run and cemented across the section. Again, this requires that perforations be made through the casing and cement to reach the zone(s) of interest and allow well fluids to flow into the wellbore. Methods of completing a well in perforated cemented casing completions are: a) Standard Perforated Cemented Casing See Figure 1.5a for a multiple pay zone completion. b) Internal Gravel Packs This is where the production casing is cemented. Perforation of the producing interval(s) is then performed and the perforations cleaned out. A screen is run and gravel is pumped into the casing/screen annulus and the perforation tunnels; See Figure 1.5b. NOTE:

Cased and perforated completions are the most common types of completions performed today since they offer selective pay zone (or pay section) perforating and enable selective stimulation.

Advantages of Perforated Casing or Liner Completions are: • • • • • • •

Is safer during well completion operations. Effect of formation damage is minimal. Excessive water or gas production may be controlled or eliminated. The zones can be selectively stimulated. The liner impedes sand influx. The well can be easily deepened. Is easier to plan for completing.

Disadvantages of Perforated Casing or Liner Completions are: • • • •

The wellbore diameter through the pay zone(s) is restricted. Log interpretation is critical. Liner cementation is more difficult to obtain than casing cementation. Perforating, cementing and rig time incurs additional costs.


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Cement Liner Hanger Perforations

Production Casing Screened Liner Graded Gravel

Formation

Formation

Formation

Formation

Formation

a) Standard

b) Internal Gravel Pack

Figure 1.5- Perforated Cemented Casing Schematics

1.2.2 Classification-by Mode Of Production When the hydrocarbon reservoir can sustain flow due to its natural pressure, flow may be up the production casing string, up the tubing string, or both. Tubingless Completions Casing flow completions are a particularly low-cost method in marginal flow conditions such as low rate gas wells; See Figure 1.6a. NOTE:

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Casing flow completions are not normally used by most operators, primarily because the production casing is exposed to well pressure and/or corrosive fluids. Tubingless completions are potentially hazardous especially in offshore installations. As there is an increased risk of collision damage offshore and there is no facility to install downhole safety valves. The use of casing flow production methods are discouraged both offshore and onshore.


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Tubing Flow Completions Tubing flow completions utilise the tubing to convey well fluids to surface. Flow rate potential is much lower in tubing flow than in unrestricted casing flow completions. As well as for production, the tubing string can be utilised as a kill string or for the injection of chemicals. Tubing strings may also accommodate gas lift valves which essentially ‘gas assist’ well liquids to surface; these valves would be installed if formation pressure diminished considerably and natural drive ceased. By far the most common methods of completing a well is to use a single tubing string/packer system where the packer is installed in the production casing to offer casing protection, subsurface well control, and an anchor for the tubing. Examples of such completions methods are: • •

Simple low cost (temporary); See Figure 1.6b High pressure; See Figure 1.6c.

Other equipment commonly installed in the tubing string to facilitate a safer production system may be: •

Wireline Nipples

-

Permits The Installation Of Flow Controls Or Plugs.

•

Tubing Retrievable Safety Valve

-

For Emergency Well Shut-In.

•

Safety Valve Landing Nipple

Permits The Installation Of A Surface Controlled Sub-Surface Safety Valve (SCSSV) For Emergency Shut-In.

•

Flow couplings

-

Absorbs Erosion Caused By Turbulence And Abrasion.

•

Circulating Device

-

Fitted Above The Packer For Circulating Purposes

•

Tubing Seal Device

-

To Allow Tubing Movement.

A polished bore receptacle (PBR) in a liner hanger is often used in place of a packer, e.g. in a high rate liner or monobore completion; See Figure 1.6d. Refer to Section 1.3 for completion equipment.


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High Rate Liner or Monobore These are utilised in deep wells where tubing/casing clearances are small and for high productivity wells where the use of a packer would restrict the flow of well fluids; See Figure 1.6d. In general, tubing and packer installations depend on the completion requirements and economic considerations.The completion engineer should consider the following factors for tubing/packer type completion installations: • Simplification of the completion for future well servicing operations (i.e. wireline, coiled tubing, snubbing etc.). • Optimum tubing size for maximum long term flow rate. • Future artificial lift needs. • Bottom hole pressure and temperature gauge survey hang off system. • Seal movement device to accommodate tubing elongation or contraction. • Availability of downhole circulating device. • Requirements for downhole corrosion inhibitor injection. • Requirements for downhole hydrate inhibitors. • Tubing-conveyed perforating (TCP) guns and/or through tubing guns for underbalanced perforating. • Fluids to be used i.e. drilling muds, completion fluid, wellbore fluid. • Well killing. The monobore completion was developed primarily for the North Sea area by operators to reduce the high cost of well servicing operations.The monobore, termed from the production liner and tubing having the same or similar size bores, allows much improved servicing capability by the use of ‘through tubing’ tools and services to conduct many operations which had previously required the tubing to be pulled from the well. A liner packer and PBR is used in place of the conventional type packer to maintain the fullest bore size. Some versions are ‘full bore’ completions to retain maximum bore size which are serviced with retrievable through tubing bridge plugs or nippleless wireline locks (such as the Halliburton Monolock system) that can be set in the tubing or liner bore.

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Production Tubing Production Casing Gas Lift Valve Cement

Small Diameter Casing or Large Diameter Tubing

Retrievable Packer

Cement

No Go Wireline Seating Nipple

Perforations

Formation

b) Temporary Tubing

a) Tubingless

Chemical Injection Valve Permanent Packer Sliding Sleeve

Polished Bore Receptacle

Large Diameter Tubing

Millout Extension Perforated Joint

Sliding Sleeve Liner Hanger

No Go Nipple

Cement Liner

c) High Pressure

d) High Rate Liner

Figure 1.6 - Flowing Wells (Single String) Schematics


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Artificial Lift When a reservoir’s natural pressure is insufficient to deliver liquids to surface production facilities, artificial lift methods are necessary to enhance recovery. Various artificial lift completions methods, See Figure 1.7, and their key completion considerations are: a) Rod Pump Lift These pumps consist of a cylinder and piston with an intake and discharge valve. Vertical reciprocation of the rod will displace well fluid into the tubing; See Figure 1.7a. These are utilised in low to moderate wells which deliver less than 2,000 BPD (318 m3/day). Key considerations are: • • • •

The annulus is open. A tubing anchor may be required. The pump diameter must be adequate. The rods must be properly sized.

b) Hydraulic Pump Lift Hydraulic pump lift is utilised in crooked holes, for heavy oils and variable production conditions that cause problems for conventional rod pumping. Three types of hydraulic pump exist to lift liquid: Piston

Consists of a set of coupled pistons, one driven by a power fluid and the other pumping the well fluid; systems exist for production up the annulus, See Figure 1.7b, or up the tubing.

Jet

Converts power fluid to a high velocity jet which pulls the well fluid up into the flow stream.

Turbine

Power fluid rotates a shaft on which a centrifugal or axial pump is mounted; See Figure 1.7c.

Key considerations are: • • • • • • •

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The number of flow conduits (production and power). Pressure losses in the power and return lines. Whether produced liquid can return up the casing. Lubricator access to pump-in jet or piston units. The large casing size required for turbine units. The power fluid/oil separation facilities required. The higher initial costs.


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c) Plunger Lift The plunger lift system, See Figure 1.7d, is a low rate lift system in which annulus gas energy is used to drive a plunger carrying a small slug of liquid up the tubing when the well is opened at surface. Subsequent closing of the well allows the plunger to fall back to bottom. Plunger lift is useful for de-watering low rate gas wells. Key considerations are: • • •

The tubing must be drifted prior to installation. The annulus is open to store lift gas. A nipple/collar stop must be installed to support a catcher and shock absorber.

d) Electric Submersible Pump (ESP) An ESP is used for moving large liquid volumes of low gas/liquid ratio from reservoirs with temperatures below 250˚F, e.g. water supply wells, high water cut producers and high deliverability undersaturated oil wells; See Figure 1.7e. Key considerations are: • • • • •

The annulus is open to atmosphere for gas venting (but not offshore). A special wellhead is required for cable sealing. Some cable protection is needed. Motor cooling must be adequate. The tubing size must be adequate to handle large volumes with minimum back pressure on the pump.


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Rod Tubing

Plunger

Tubing Anchor / Packer

Pump Housing

Travelling Valve Fluid Level

Standing Valve

Standing Valve

a) Rod Pump

Pump Seat Nipple

b) Piston Pump

Turbine

Electric Cable

Liquid Load Pump

Standing Valve Bumper Spring

Pump

Tubing Stop

Intake Protector

Packer

Motor

c) Turbine

d) Plunger Lift

e) Electric Submersible Pump

Figure 1.7 - Pump and Plunger Artificial Lift Methods

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e) Gas Lift Gas lift supplements the flow process by the addition of compressed gas which lightens the liquid head, reduces the liquid viscosity, reduces friction and supplies potential energy in the form of gas expansion; See Figure 1.8. Continuous gas lift is used to lift liquid from reservoirs that have a high productivity index (PI) and a high bottom hole pressure BHP. Intermittent lift is used in reservoirs that exhibit low PI/low BHP, low PI/high BHP, or high PI/low BHP. Liquid production can range from 300 - 4,000 bbls/day (48 - 636 m3/day) through normal size tubing strings. Casing flow can lift up to 25,000 bbls/day (3,975 m3/day). Key considerations are: • • •

Tubing size. The need for a packer. Setting depths for gas-lift valves.

Gas In Gas Lift Valves

Packer

b) Piston Pump

Figure 1.8 - Gas Lift


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1.2.3 Classification-by Number of Zones Completed Single Zone Completions Flowing wells that are equipped with a single tubing string are usually completed with a packer. Single zone completions include the downhole co-mingling of production from several intervals within a pay zone. Examples of single zone completions are shown in Figure 1.9, i.e.: a) Standard See Figure 1.9a. b) Interval Co-mingling See Figure 1.9b. At the design stage, the following options should be considered and possibly built into the completion: • • •

The optimum tubing size for maximum long term flow rate. Future artificial lift needs. Future well servicing operations.

Tubing

Packer

a) Standard

b) Interval Co-mingling

Figure 1.9 - Single Zone Completion Schematics

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Multiple Zone Completions When a well encounters multiple pay zones a decision must be made either to: •

Produce the zones individually, one after the other, through a single tubing string and the annulus.

•

Complete the well with multiple tubing strings and produce several zones simultaneously.

•

Co-mingle several zones in a single completion.

•

Produce only one zone from that well and drill additional wells to produce from the other pay zones.

Examples of multiple zone completions are shown in Figure 1.10. a) Single String Dual Completion This is the most basic dual completion where production of the lower zone is up the tubing and production of the upper zone is up the casing/tubing annulus; See Figure 1.10a. b) Twin String Dual Completion Separate flow from each zone is maintained by the use of two tubing strings and two packers; See Figure 1.10b. NOTE:

With the installation of gas lift valves in the two tubing strings, artificial lift can be initiated at a later date.

c) Multiple String Completions Separate flow from each zone can be maintained by the use of three tubing strings and three packers; See Figure 1.10c. Such completions provide a method of individual zone production and can improve some field economics. However, in general, such completions are difficult to install and are usually too restrictive in regard to total well production, due to the small tubing sizes, to be economically attractive in most cases. Furthermore, the difficulty of carrying out future remedial well operations of such wells prevent their widespread use.


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d) Concentric String Completions Concentric strings require less clearance and can often achieve a higher overall flow capability; See Figure 1.10d . The advantages of Multiple Zone Completions: • •

Some individual zone production. Reduced well cost.

Disadvantages of Multiple Zone Completions are: • • • •

Production casing is exposed to well pressure and corrosive fluids. Tubing can be stuck in place due to solids settling from the upper zone. The lower zone must be killed or plugged off before servicing can be done on the upper zone. The lower zone must be plugged off to measure any flowing bottomhole temperature associated with the upper zone.

NOTE:

Multi-zone completions not only provide the separation of various zones but also the separation of individual pay sections within a thick pay zone.

e) Annulus Configurations It is normal practice to identify an annulus configuration by an alphabetic progression from internal to external casing strings. The ‘A’ annulus is defined as the annulus within the production/liner casing. An active annulus refers to any annulus being used for circulation purposes. An inactive annulus refers a non-circulatable annulus e.g. any annulus formed between two strings of cemented casings. In the case of a well having an extra annulus between the production casing and the tubing, this annulus is identified separately e.g. a well on artificial lift using hydraulic pumping will have a ‘drive’ annulus.

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Dual Packer

Packer

b) Twin String Dual

Concentric Tubing Strings Triple Packer

Single Packers

Blast Joint

c) Multiple String

d) Concentric String

Figure 1.10 - Multiple Zone Completion Schematics


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1.2.4 Horizontal Completions In a vertical wellbore, the state of technology is such that it can be successfully cased, cemented, completed, producing zone or zones perforated and cleaned up, produced and, if the level of production is not economical, various means of stimulation (hydraulic fracturing, acidisation) used on the formation to increase productivity. By contrast, the drilling of horizontal wells and their subsequent study has indicated substantial increases in production rates as compared to unfractured vertical wells. As a result, there is now great incentive to investigate the technology required to drill, complete, test, stimulate and properly produce horizontal wells which, due to increased production, can lead to significant improvements in field economics. From the drilling point of view, horizontal wells are classified as having ultra-short, short, medium or long turning radii into a horizontal plane.The geometrical characteristics of such horizontal wells are given in Table 1.1. NOTE:

‘Multi-zonal’ wells are prime candidates for horizontal completions as are formations that have naturally fractured networks from which large production increases can be expected; See Figure 1.11.

Figure 1.12 shows some of the methods used to complete horizontal wells. A classification of completions for horizontal wells is shown in Figure 1.13.

Type

Drilling Method

Turning Radius (Build-Up Radius)

Horizontal Length

Ultrashort (drainhole)

Waterjet

1-2f (-)

100 - 200 ft.

Short

Whipstock. Curved drilling entry guide flexible drilling collars

20 - 40 ft (-)

200 - 700 ft.

Medium

Downhole mud motor. Flexibleheavy weight drill pipe

300 - 500 ft. (19 - 11 deg./100 ft.)

700 - 2,000 ft.

Long

Conventional drilling tools

600 - 2,000 ft (10 - 3 deg./100 ft.)

> 2,000 ft.

Table 1.1 - Geometrical Characteristics of Horizontal Well Completions

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Oil Accumulations Wellbore

Figure 1.11 - Naturally Fractured Formations

Open Hole This is the most economical type of completion where removal of mud and debris from the horizontal section is the primary stimulation performed. If additional stimulation is required, tubing or coiled tubing can be run to TD, stimulation fluid spotted into the horizontal section and then pumped into the formation; See Figure 1.12a. Slotted Liner This type of completion is used in the possible event of hole collapse. It is used in reservoirs that will flow naturally and where no stimulation treatments are necessary; See Figure 1.12b. External Casing Packers These are used for control of a single interval in the whole horizontal section of a reservoir that has different zones producing hydrocarbons. They also control water production from selective zones. External casing packers and closeable ported subs are useful in controlling unwanted production from formations along the horizontal section; See Figure 1.12c. Packers of this type are commonly used to separate productive zones, either with or without cement. Similarly, because of the difficulty in cementing horizontal liners, many horizontal production strings are run without cementing. For uncemented liner completions, the application of rotation can be utilised to deflate the packer for retrieval.


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a) Open Hole

c) Uncemented Liner

b) Slotted Liner

d) Cement Liner

Figure 1.12 - Some Methods of Completing Horizontal Wells

Fracture Stimulation In this type of completion production casing or liner is cemented into the horizontal section. After perforating, controlled stimulation treatments (matrix and fracture) can be performed efficiently; See Figure 1.12d. In a horizontal hole, the completion problems are more complex than in vertical wells. For example, any debris in the horizontal well bore will remain in situ and create an obstacle for moving tools or instruments. Similarly, gravity will have a profound effect on various tools in the horizontal section of the wellbore and effective centralisation and friction reduction is necessary by using roller stem. Completion equipment currently available is capable of working satisfactorily in a horizontal well with little or no modification. The main area requiring development is in coiled tubing conveyed tools (equivalent to wireline tools). Some advance has been made with the development of sliding sleeves, mounted in the horizontal section of wells, which can be opened and closed using a coiled tubing conveyed shifting tool. Similarly, coiled tubing manipulation tools exist for packer setting in horizontal sections. 1-24


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Interface Between Wellbore and Reservoir

Vertical / Deviated Wells

Horizontal Wells

See Figure 1.1

(l,m,s)

(l,m) Uncemented Liner

Open Hole

External Casing Plaster

(l) Cemented Casing or Liner

l - long m - medium s - short

Slotted (l,m,s)

Pre-packed (l,m)

Gravel Packed (l,m)

Figure 1.13 - Classification of Completions for Horizontal Wells


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1.2.5 Subsea Completions Offshore fields are increasingly being developed with subsea wells. In the early days subsea wells were extensively used as satellite wells only, usually located a distance away from the main production platform outside the normal reach limitations for deviated wells. Today entire fields can be produced through subsea wells to floating production systems or to nearby platforms on other fields. Subsea well top hole locations are generally clustered together (sometimes in a subsea manifold) to share production and control line facilities although single satellites are still occasionally used. Developing an offshore field with subsea wells is a very economic method but has a drawback from the completions point of view in that vertical access requirements for well servicing intervention will inevitably be high with the need to use a MODU (Mobile Offshore Drilling Unit) or other type of well servicing vessel. Some wells have been clustered under the floating production facilities to allow vertical re-entry from the vessel, thereby reducing servicing costs. Nowadays, the availability of long-service life tubing retrievable sub-surface safety valves (TRSVs) with all metal-to-metal technology minimise the need for mechanical servicing. 'Through flowline' (TFL) servicing (see Figures 1.14 &1.15) also reduces servicing costs and is especially useful on highly deviated wells. However, no matter the attractiveness of utilising TFL systems in completion design the operational complexity, rate restriction and cost, should not be underestimated and through experience most users of TFL have now abandoned it's use due to its associated problems. In a completed subsea well, high pressure losses can occur in the flowlines connected to surface production facilities and it is common to minimise this by incorporating gas lift valves or hydraulic pumping equipment in the completion. Subsea flowlines are also subject to substantial cooling which may result in poor oil flow properties and the requirement to install methanol injection systems in subsea components to minimise the risk of hydrate formation . Figure 1.16 shows a typical subsea wellhead arrangement.

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Fig. 1.14 - Dual String, Driver-Assist Flowlines, TFL, Satellite Tree


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Fig. 1.15 - TFL Pumpdown Components

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Scrap view of corrosion cap running tool / corrosion cap stinger interface. 4 (Scale 1:2)

12

Corrosion Cap Running Tool P.No. 541081-A

128.4" (3.3m) 114.3" (2.9m)

3

8

2

6

4 Injection Tree Assy P.No. 541010-A

1

1. 2. 3. I.L.M.

2

0 Feet Datum Top Of Wellhead

0 Meter Datum

-2

-1 Permanent Guide Base P.No. 540869

-4

-6

Fig. 1.16 Typical Subsea Wellhead System


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Alternative Arrangement Running Corrosion Cap On Drill Pipe

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1.2.6 Subsea Well Interventions Subsea wells can be serviced by means of subsea workover systems. There are two systems in current use, one for conventional subsea trees (Figure 1.17) and the other for the newer generation of spool trees (horizontal tree, Figure 1.18). Each of these is described below : Conventional Subsea Well Interventions Conventional subsea well interventions are conducted through a subsea workover riser systems which are deployed from floating vessels or from jack-up rigs in shallower waters. Riser systems are attached to the top of subsea Xmas trees and, after completing the appropriate test procedures, allow live well servicing by wireline or coiled tubing methods. Pressure control is provided at surface by a Xmas tree fitted with a lift frame which accommodates the pressure control equipment installed on the top of the tree. Other than this, pressure control is exactly the same as that described in the previous sections except that vessel movement gives additional rigging up and operational problems. However, the workover riser system must also have subsea pressure control capabilities in the event of a emergency disconnection or a riser failure. Subsea pressure control is provided by a subsea lower riser assembly (LRA) and an emergency disconnect package (EDP) which can safely close in the well and disconnect the riser, with or without wireline or coiled tubing through the subsea tree, in the event of an emergency. These systems maintain the well in a safe condition until the problems arisen are overcome and the riser can be re-attached. Operations can then be recommenced and fishing operations initiated, if required. A typical subsea workover riser system is shown in Figure 1.19. Spool Subsea Tree Interventions Due to the capital costs of conventional workover riser systems, and the incompatibility between the various manufacturer's designs, this drove the industry to develop the spool tree and associated intervention systems utilising standard drilling rig subsea BOP riser systems. The subsea BOPs were utilised for connection to the tree and to provide pressure control in conjunction with a subsea test tree which latches onto the spool tree tubing hanger. Pressure is contained within the subsea tree and it's riser to the surface which is terminated with a surface test tree in the conventional well test fashion. The BOP rams are closed on the subsea test tree slick joint to provide a barrier to any well pressure below the BOPs. In the event of an emergency, the subsea tree can be closed, the subsea riser disconnected before the BOP shear/ blind rams are closed above the tree valve section and the drilling riser disconnected. The main problem thrown up by this method of well intervention was the lack of bore size in standard subsea test tree riser systems initially available which has driven the design of systems with bores sizes now up to 7 inches in diameter. Subsea test tree systems must have a cutting capability to sever any wireline or coiled tubing run through the BOPs. See Figure 1.20 for typical spool tree workover system. 1-30


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Production Swab Valve Crossover Valve

Production Wing Valve Production Upper Master Valve

Annulus Master Valve

Production Lower Master Valve

Wire Line Plug Profiles

Fig. 1.17 - Classic Conventional Tree Configuration


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DEBRIS CAP WIRELINE PLUGS INTERNAL ISOLATION CAP WORKOVER VALVE CROSSOVER VALVE PRODUCTION MASTER VALVE

PRODUCTION ISOLATION VALVE ANNULUS ISOLATION VALVE

ANNULUS MASTER VALVE

Fig. 1.18 - Typical Horizontal tree Configuration

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Fig. 1.19 - Typical Subsea Workover Riser System


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Figure 1.20 - Typical Subsea Spool Tree Workover System

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1.3 COMPLETION EQUIPMENT In general, a well completion should provide a production conduit which: • •

Maximises the safe recovery of hydrocarbons from a gas or oil well throughout its producing life. Gives an effective means of pressurising selected zones in water injection wells.

Downhole accessories used should be designed to provide the safe installation and retrieval of the completion, and flexibility for sub-surface maintenance of the well using wireline, coiled tubing or other methods. Even though different types of wells present distinct design and installation problems for engineers, most completions are just variations on a few basic designs types and, therefore, the equipment used is fairly standard. An overview of the equipment commonly used in single and dual string completions is given in the following sections. The detailed operation of some the items such as sliding side doors (SSDs), side pocket mandrels (SPMs) and packers will not be covered in this manual. However, the relative location of these tools in a completion and their functions in intervention work or workovers will be addressed. Figure 1.21 shows a schematic drawing illustrating the location of equipment in a typical oil well completion. Each common item in the completion string is described in the following sections.


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Tubing Hanger Tubing SCSSV Control Line Production Casing

Flow Coupling SCSSV Landing Nipple Flow Coupling

Side Pocket Mandrel (SPM)

SPM

SPM

SPM

SPM

Flow Coupling Sliding Side Door (SSD) Flow Coupling

Landing Nipple Pup Joint

Packer

Cross-Over Landing Nipple Perforated Joint Landing Nipple Pup Joint

Wireline Re-Entry Guide

Figure 1.21 - Typical Oilwell Completion

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1.3.1 Wireline Re-entry Guide A wireline entry guide is used for the safe re-entry of wireline tools from the casing or liner back into the tubing string. It attaches to the end of the production string or packer tailpipe assembly and has a chamfered lead in with a full inside diameter. Wireline re-entry guides are generally available in two forms: Bell Guide This guide has a 45 degree lead in taper to allow re-entry into the tubing of wireline tools. This type of guide, See Figure 1.22a, is used in completions where the end of the tubing does not need to pass through any casing obstacles such as liner laps. Mule-Shoe Re-entry Guide This type of guide is essentially the same as the Bell Guide but incorporates a large 45 degree angle cut on one side of the guide; See Figure 1.22b. Should the guide hang up on any casing item such as a liner lip while being run, rotation of the tubing will cause the 45 degree shoulder to slide past the liner lip and enter the liner.

45 Chamfer

45 Taper

a) Bell Guide

b) Mule Shoe Guide

Figure 1.22 - Wireline Re-entry Guide


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1.3.2 Tubing Protection Joint This is a normally a single joint of tubing installed for the particular purpose of providing protection for wireline installed bottomhole pressure and temperature gauges from buffeting in the flow stream. This protection joint is installed directly below the gauge hanger landing nipple in the tailpipe below the packer and must be long enough to accommodate the longest BHP toolstring which may be run. 1.3.3 Wireline Landing Nipples Landing nipples, See Figure 1.23, are short profiled tubulars installed in strategic positions in the tubing string into which various wireline retrievable flow controls can be set and locked. These can seal within the nipple bore, if required dependent upon the tools function. The most common tools run are plugs, chokes, and pressure and temperature gauges. The main features of a landing nipple are: • • •

Locking groove or profile. Polished seal bore. No-Go shoulder (only on non-selective nipples).

Landing nipples are supplied in ranges to suit most tubing sizes and weights with API or premium connections and are available in two basic types: • •

No-Go or Non-Selective. Selective.

No-Go or Non-Selective The non-selective nipple receives a locking device which uses a No-Go principle for the purposes of location.This requires that the OD of the locking device is slightly larger than the No-Go diameter of the nipple.The No-Go diameter is usually a small shoulder located below the packing bore (bottom No-Go) but in some designs, the top of the packing bore itself is used as the No-Go. Only one No-Go landing nipple of a particular size should be used in a completion string. In most completions other than monobores, it is common practice to use a bottom No-Go nipple as the last nipple in the packer tailpipe to prevent dropped tools falling into the sump. As the No-Go provides a positive location, they are widely used in high angle wells where wireline tool manipulation is difficult and weight indicator sensitivity reduced.

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Selective In the selective system, the locking devices are designed with the same key profile as the nipples and the means of nipple selection is determined by operation of the running tool and the setting procedure. The selective design is full bore and allows the installation of several nipples of the same size. Uses of landing nipples: •

Well plugging from above, below or from both directions.

•

Pressure testing the tubing, leak finding.

•

Safety valves, chokes and other flow control devices.

•

Installation of bottomhole pressure and temperature gauges.

Orientation Groove Key Profile

Orientation Groove Key Profile

Seal Bore

Seal Bore Trash Groove No-Go Shoulder

'X' Selective Landing Nipple

'XN' No Go Landing Nipple

Figure 1.23- Halliburton Wireline Landing Nipples


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1.3.4 Perforated Joints In wells where flowing velocities are high, a restriction in the tubing, such as a gauge hanger, can cause false pressure and temperature readings.Also, vibrations in the tool can cause extensive damage to delicate instruments. To provide an alternative flow path, a perforated joint is installed above the gauge hanger nipple which allows unrestricted flow around the gauge toolstring eliminating these hazards.The perforated joint is normally a full tubing joint which is drilled with sufficient holes to provide a flow area greater than that in the tubing above. 1.3.5 Blast Joints Blast joints are installed opposite perforations (non gravel packed) where external cutting or abrasive action occurs caused by produced well fluids or sand.They are heavy-walled tubulars available usually in 10, 15, and 20 ft. lengths . They should be long enough to extend at least 4 ft. on either side of a perforated interval. 1.3.6 Packers A packer is a device used to provide a seal between the tubing and the casing. With a suitable completion string, this seal allows the flow of reservoir fluids from the producing formation to be contained within the tubing up to the surface. This protects the casing from being exposed to well pressure and to corrosion from well or injection fluids. A packer is tubular in construction and consists basically of: • •

Case hardened slips to bite into the casing wall and hold the packer in position against pressure and tubing forces. Packing elements which seal against the casing.

Figure 1.24 gives examples of typical packer installations and Figure 1.19 shows common types of packer. In general, packers are classified in three groups: • • •

Retrievable. Permanent. Permanent/Retrievable.

Packers may be further classified according to the number of bores required for production i.e. Single Dual Triple

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One concentric bore through the packer for use with a single tubing string. Two parallel bores through the packer for use with two tubing strings. Three parallel bores through the packer for use with three tubing strings.


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A typical packer description, therefore, might be: 95/8 ins. Dual 31/2 ins. x 31/2 ins. Hydraulicset Retrievable Packer. Retrievable Packers These are generally run into the wellbore on the production tubing string. As the name implies, retrievable packers can be recovered from the well after setting by pulling it with the tubing. Permanent Packers These are installed in the wellbore usually independent of the production tubing string. A permanent packer may be considered as an integral part of the casing. Permanent packers can only be removed from the well by milling operations. Permanent/Retrievable Packers As their name may suggest, these packers have the same characteristics as permanent packers but can be released and recovered from the well without milling. They will generally have a smaller bore than a permanent packer to accommodate the addition of some type of releasing mechanism. Packers, both retrievable and permanent versions, are installed in the production casing by one of the following methods: Mechanically ; Run on a workstring, is set by manipulation of the tubing i.e. by applying compression or tension in combination with rotation depending on the particular setting mechanism of the packer. NOTE:

Packers having rotation set/release mechanisms should not be used in highly deviated wells since the application of tubing torque may not be transferred downhole.

Hydraulically ; Can be run on a workstring or on the tubing string. When the desired setting depth is reached the tubing is plugged below the packer with a check valve, standing valve or a wireline plug and hydraulic pressure applied to the tubing to set the packer. Generally, a predetermined upward pull on the tubing string will release the seal unit from the packer with a Hydraulic Permanent packer system. On Electric Wireline ; This is generally restricted to permanent packers. The packer is attached to a wireline setting adapter, connected to a setting gun on the end of the wireline and run in the wellbore. On reaching the desired depth an electrical signal transmitted to the gun activates an explosive charge and, through a hydraulic chamber, provides the mechanical forces to set the packer.


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Casing

Annulus Production Tubing

Packer

Producing Formation

Production Casing

Single Zone Completion Dual Packer

Short Tubing String

Long Tubing String Upper Formation

Single Packer

Lower Formation

Packer 1

Dual Completion

Zone 1

Packer 2

Zone 2

Packer 3

Zone 3 Single String Multi Zone Completion

Figure 1.24 - Examples Of Packer Installations

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Figure 1.25 - Examples Of Common Types of Packers


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1.3.7 Permanent Packer Accessories An important aspect in a completion with a permanent packer is the tubing/packer seal. As the packer in effect becomes part of the casing after it is set, the tubing must connect to the packer in a fashion so that it can be released.This connection whether it be a straight stab in, latched or otherwise, must have a seal to isolate the annulus from well fluids and pressures. This seal usually consists of a number of seal elements to cater for some wear and tear. These seal elements are classified into two groups; premium and non-premium.The premium group are those used in severe or sour well conditions i.e. H2S, CO2 etc. and are normally ‘V’ type packing stacks containing various packing materials resistant to the particular environment. The non-premium seals are for sweet service and can be either ‘V’ type packing stacks or moulded rubber elements. Locator Tubing Seal Assemblies Locator tubing seal assemblies, See Figure 1.26a and Figure 1.26b, are fitted with a series of external seals providing an effective seal between the tubing and packer bore. They also have a No-Go type locator for position determination within the packer. Locator seal assemblies are normally space out so that they can accommodate both upward and downward tubing movement induced by changes in temperature and pressure. Seal Bore Extensions A seal bore extension is used to provide additional sealing bore length when a longer seal assembly is run to accommodate greater tubing movement. The seal bore extension is run below the packer and has the same ID as the packer. Anchor Tubing Seal Assemblies Anchor tubing seal assemblies, See Figure 1.26c and Figure 1.26d, are used where it is necessary to anchor the tubing to a permanent packer while retaining the option to unlatch when required. Anchor latches are normally used where well conditions require the tubing to be landed in tension or where insufficient weight is available to prevent seal movement. Polished Bore Receptacles (PBRs) A PBR is simply a seal receptacle attached to the top of a permanent packer or liner hanger packer in which the seal assembly lands instead of the packer bore. As the PBR bore can be made larger than the packer, this provides a larger flow area through the seal assembly. See Figure 1.23 Tubing Seal Receptacles A TSR is an inverted version of a PBR where by a polished OD male member is attached to the top of the packer and the female (or overshot) is attached tubing. The seals are contained in the female member so that they are recovered when pulling the tubing. See Figure 1.24

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No-Go Shoulder

"E" Spacer Seal Sub

"E" Spacer Seal Sub

b) Seal Extension

a) Locator Tubing Seal Assembly

"E" Anchor Seal Sub

Anchor Latch

Anchor Latch

"E" Spacer Seal Sub

c) “K-22” Anchor Seal Nipple

d) “EBH-22” Anchor Seal Assembly

Figure 1.26 - Permanent Packer Seal Accessories © ABERDEEN DRILLING SCHOOLS 2002

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Connection

Debris Barrier Unit Shear Ring (Closed Position)

Seal Units

Debris Barrier Unit

Debris Barrier Unit

Debris Barrier Unit

Connection

Figure 1.27 - Polished Bore Receptacle

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Figure 1.28 - Tubing Seal Receptacle


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1.3.8 Sliding Side Doors (SSDs) Sliding Side Doors (SSDs) or Sliding Sleeves are installed in the tubing during well completion to provide a means of communication between the tubing and the annulus when opened; See Figure 1.29. SSDs are used to: • • •

Bring a well into production after drilling or workover by circulating the completion fluid out of the tubing and replacing it with a lighter underbalanced fluid. Kill a well prior to pulling the tubing in a workover operation. Provide selective zone production in a multiple zone well completion.

SSDs are available in versions which open by shifting an inner sleeve either upwards or downwards. A number of SSDs can be installed in a completion string and selectively opened or closed by the use of the appropriate wireline shifting tool. CAUTION:

Tubing and annulus pressures must be equalised before an SSD sleeve is opened to prevent wireline tools being blown up or down the tubing.

A common fault of sliding sleeves is that the seal failure usually leads to a workover although a pack-off can be installed as a temporary solution.

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Figure 1.29 - Sliding Side Door (SSD)


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1.3.9 Flow Couplings Flow couplings, which are heavy-walled tubulars, are installed above and below any completion component which may cause flow turbulence such as wireline nipples, SSDs, SCSSV landing nipples etc., to cater for internal erosion.Although the same amount of erosion is experienced, the added thickness of the flow coupling provides enough material to prevent weakening over the projected life of the well. In lower velocity wells, such as low GOR oil wells, a flow coupling may only be needed to be placed above restrictions.

1.3.10 Side Pocket Mandrels Side Pocket Mandrels (SPMs) were originally designed for gas lift completions to provide a means of injecting gas from the casing-tubing annulus to the tubing via a gas lift valve. However in recent times, they have also been commonly used in place of an SSD as a circulating device because seal failure can be rectified by pulling the dummy gas lift valve (or kill valve) with wireline and replacing the seals. SPMs are installed in the completion string to act as receptacles for the following range of devices: • • • • • •

Gas lift valves Dummy valves Chemical injection valves Circulation valves Differential dump kill valves Equalising valves.

It is essential to understand the operation of the device installed in an SPM before conducting any well intervention as it may affect well control. See Figure 1.24 for a typical SPM and Figure 1.31 for types of valves. Gas Lift Valves There are many different designs for gas lift valves for various applications. They range from being simple orifice valves to pressure operated bellows type valves. However, they all contain check valves to prevent tubing to annulus flow. These check valves may leak after a period of use and they should never be relied on as barriers in a well control situation.These should be replaced with dummy valves and the tubing pressure tested to confirm integrity. Dummy Valves These are tubing/annulus isolation valves. They are installed in place of the valves in order that the completion tubing string can be pressure tested from both sides during installation or when well service operations are required.

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Chemical Injection Valves The injection valve is designed to control the flow of chemicals injected into the production fluid at the depth of the valve. A spring provides the force necessary to maintain the valve in the fail-safe closed position. Reverse flow check valves, which prevent backflow and circulation from the tubing to the casing, are included as an integral part of the valve assembly. Injection chemicals enter the valve from the annulus in an open injection system. (This requires the annulus to be full of the desired chemical. An alternative method is to run an injection line from surface to the SPM.) When the hydraulic pressure of the injected chemicals overcomes the pre-set tension in the valve spring plus the pressure in the tubing, the valve opens. Chemicals then flow through the crossover seat in the valve and into the tubing. Circulating Valves These are recommended to be installed in the SPM whenever any circulating is to carried out.The circulating valve is designed to enable circulation of fluid through the SPM without damaging the pocket.The valve allows fluid to be dispersed from both ends allowing circulation of fluid at a minimal pressure drop. Some valves permit circulation from the casing into the tubing only and others to circulate fluid from the tubing into the casing only. If a circulating valve is not used and the pocket is flow cut a workover would be necessary to replace the SPM. Differential Dump Kill Valves Differential dump/kill valves are designed to provide a means of communication between the casing annulus and the tubing when an appropriate differential pressure occurs. Below a preset differential pressure, the valve acts as a dummy valve since it uses a moveable piston to block off the circulating ports in the valve and the side pocket mandrel. The differential pressure necessary to open the valve will depend on the type and number of shear screws installed.The valve will only open when the casing annulus pressure is increased by the differential (of the shear screw rating) above the tubing pressure. An increase in tubing pressure above the casing annulus pressure will not open the valve. After opening, the piston is locked in the up position and fluids can flow freely in either direction.The hydrostatic pressure from the column of annulus fluid will kill the well and remedial operations can be planned. Equalising Valves The equalisation valve is designed to equalise pressure between tubing and casing and/or to circulate fluid before pulling the valve from the SPM. The valve has two sets of packing which straddle and pack off the casing ports in the SPM. The tubing and annulus are isolated from each other until the equalising device is operated by a pulling tool. Pressures equalise through a port before the valve and latch are retrieved.


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"KBUG"

Orienting Sleeve

Tool Discriminator

Latch Lug Upper Packing Bore

Pocket Lower Packing Bore

Section A - A Figure 1.30- Side Pocket Mandrel (SPM)

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Running Neck Pulling Neck Tangential Shear Pin Spring Latch Ring

['RKP' Latch]

Packing Stack

Reverse Flow Check

Spring

Communication Port

Packing Stack Packing Stack Shear Screw

Packing Stack

Communication Port Piston

Communication Port

Packing Stack

Reverse Flow Check

Reverse Flow Check

Packing Stack

[’DCR-1’]

[’LK - 3’]

[’RG - 2’]

Figure 1.31 - Types of SPM Valves


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1.3.11 Travel Joints A travel joint is used to compensate for tubing movement due to temperature and/or pressure changes during treating or production. It is normally used with a seal assembly anchored to a permanent packer. Figure 1.32 shows a Travel Joint commonly used on the short string in dual string completions. NOTE:

Alternative names for travel joints are Telescoping or Expansion joints.

Polished Bore Receptacles (PBRs) and Extra Long Tubing Seal Receptacles (ELTSRs) are other devices commonly installed above a permanent packer to compensate for tubing movement; Refer to Section 1.3.7.

Packing

Inner Sleeve Outer Sleeve

Figure 1.32 - Travel Joint

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1.3.12 Sub-Surface Safety Valves The modern sub-surface safety valve has been developed from the earliest versions produced in the 1930’s. The initial demand was for a downhole valve that would permit flow during normal conditions, but would isolate formation pressure from the wellhead to prevent damage or destruction. This valve would be installed downhole in the production string. The valve that was developed was a Sub-Surface Controlled Safety Valve (SSCSV) and was a poppet type valve with a mushroom shaped valve/seat system. Compared with today’s valves, this simple poppet type valve had several disadvantages; restricted flow area, tortuous flow paths, low differential pressure rating and calibration difficulties. Despite these limitations the valve operated successfully and other versions were developed with less tortuous flow paths such as the ball and flapper valve. From this beginning, the Surface Controlled Sub-Surface Safety Valve (SCSSV) was developed in the late 1950’s.This moved the point of control from downhole to surface; See Figure 1.33. This design provided large flow areas, remote control of opening and closing, and responsiveness to a wide variety of abnormal surface conditions (fire, line rupture, etc.). Initial demand for this valve was slow due to it’s higher cost and the problems associated in successfully installing the hydraulic control line, hence it’s usage was low until the late 1960’s. The SCSSV is controlled by hydraulic pressure supplied from a surface control system which is ideally suited to manual or automatic operation, the latter of which pioneered the sophisticated emergency shut-down systems required today. The versatility of the valve allows it to be used in specialised applications as well as in conventional systems. SCSSVs are available in two variants - Tubing Retrievable Safety Valves (TRSV) and Wireline Retrievable Safety Valves (WRSV). SCSSVs are available with ball or flapper type closure mechanisms.


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Nipple Adapter

Stainless Steel Set Screws Top Sub Jam Nut O-Ring Lock Open Ring Stainless Steel Set Screws

O-Ring Brass Shear Screws T-Seals Housing Locking Mandrel Piston O-Ring T-Seal Stainless Steel Set Screws Intermediate Sub Stainless Steel Set Screws O-Ring Stainless Steel Set Screws Piston Coupling C-Ring Flow Tube Power Spring Housing

Spring Stop O-Ring

Flapper Seat

Stainless Steel Set Screw O-Ring Flapper Base Resilient Seal Flapper Pin Torsion Spring Flapper Flapper Housing O-Ring Stainless Steel Set Screw Bottom Sub

Figure 1.33 - Example of Downhole Safety Valve

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Sub-Surface Safety Valve Applications Fail-safe Sub-Surface Safety Valves, whether directly or remotely controlled, are installed to protect personnel, property and the environment in the event of an uncontrolled well flow (or blow-out) caused by collision, equipment failure, human error, fire, leakage or sabotage. Whether safety valves are required in a particular operating area, depends on the location of the wells and in some cases on company operating policy and/or government legislation. In general, each application must be considered separately due to varied well conditions, locations, regulations, depth requirements etc. Table 1.2 shows the various applications of WRSVs and TRSVs. WRSV Applications

TRSV Applications

General application: where intervention by wireline is available

General application: where larger flow area is desired for the tubing size

High pressure gas wells

High volume oil and gas wells

Extreme hostile environments where well fluids or temperature tend to shorten the life of component materials

Subsea completions

High velocity wells with abrasive production

Multiple zone completions where several flow control devices are set beneath the TRSV Greater depth setting capabilities

Table 1.2 - Sub-Surface Safety Valve Applications


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Sub-Surface Controlled Sub-Surface Safety Valves These valves are installed in regular wireline type nipples on a lock mandrel. a)

Pressure-Differential Safety Valves

This type of direct-controlled safety valve is a ‘normally open’ valve that utilises a pressuredifferential to provide the method of valve closure. Normally a spring holds a valve off-seat until the well flow reaches a pre-determined rate. This rate can be related to the pressure differential generated across an orifice or flow bean. When this differential is reached or exceeded, a piston moves upwards against a pre-set spring force closing the valve.Valves of this type are termed ‘storm chokes’. There are two closing mechanisms available with these valves, i.e.: • •

Ball-type closure. Flapper-type closure.

The valve is held open by a spring force which may be increased by adding spacers or changing the spring. The relationship between flow rate and differential may be adjusted by changing the bean size. The valve when closed will remain in the this position until pressure is applied at surface to equalise across it when the spring will return to the open position . NOTE: This type of valve should never be attempted to be pulled unless it has been equalised and is open. These valves are rarely in use today but a derivative, the Injection Valve, which is normally closed is widely used in injection wells.This injection valve opens when fluid or gas is injected and travels to the fully open position when the predetermined minimum injection rate is reached; See Sub Section c) Injection Valve. b) Ambient Type Safety Valves This type of direct-controlled safety valve is a fail safe closed valve which is pre-charged with a calibrated dome (chamber) pressure prior to running. Ambient controlled valves will open when the well pressure reaches the set point of the dome calibration. The valve will close when the flowing pressure of the well, at the point of installation, drops below the predetermined dome pressure. Ambient type safety valves are also generally referred to as a ‘storm chokes’. This type of valve is usually a ball valve and is not limited by a flow bean which gives it a large internal diameter and, hence, a large flow area making it suitable for high volume installations possibly producing abrasive fluids. 1-58


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Ambient type safety valves are run with an equalising assembly to allow equalisation across the valve should it close, and a lock mandrel to locate and lock the valve in the landing nipple. NOTE:

c)

Both pressure differential and ambient controlled sub-surface safety valves close on pre-determined conditions.They do not offer control until these conditions exist. Also valve settings may change if flow beans become cut. Surface controlled safety valves should be considered in such cases.

Injection Valve

Injection valves are normally closed valves installed in injection wells. They act like check valves allowing the passage of the injected fluid or gas but close when injection is ceased. The closure mechanism is either a ball or flapper type which opens when the differential pressure from the injected medium equalises that below the valve. As the injection rate is increased to the precalculated rate, the differential acts on a choke bean and overcomes a spring to move the mechanism to the fully open mode. If the injection rate is insufficient or fluctuating, the mechanism will be damaged and possibly flow cut . The flapper-type valve is the most popular as its operation is less complicated and is also less prone to damage if the injection rate is not high enough. d) Bottom Hole Regulators Bottom hole regulators are essentially throttling valves installed downhole to enhance the overall safety in wells where high surface pressures or hydrate formation present problems. Bottomhole regulators are designed to reduce surface flowline pressures to safe, workable levels and to keep surface controls from freezing. In gas wells, the pressure drop across a regulator will occur downhole where the gas and surrounding well temperature is higher than at surface. The higher gas temperature and surrounding well temperature tend to prevent hydrate formation when a pressure drop occurs across the regulator.The cooler gas immediately above the regulator will usually increase due to the downhole ambient temperature. In oil wells, the installation of a bottomhole regulator is used to facilitate the liberation of gas from solution downhole and consequently lighten the oil columns to increase flow velocity . The regulator has a stem and seat which are held closed by a spring and at a pre-set differential pressure the valve opens. If high reductions in pressure are necessary, more than one regulator can be installed, providing stepped reductions reducing the risk of hydrate formation and flow cutting.


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NOTE:

An equalising sub should be installed between the lock mandrel and the regulator to facilitate the equalisation of pressure.

Surface Controlled Sub-Surface Safety Valves The SCSSV is a downhole safety device that can shut in a well in an emergency or provide a barrier between the reservoir and the surface. As the name suggests, the valve can be controlled from the surface by hydraulic pressure transmitted from a control panel through stainless steel tubing to the safety valve; See Figure 1.34 The remote operation of this type of valve from the surface can also be integrated with pilots, emergency shut down (ESD) systems, and surface safety control manifolds. This flexibility of the surface controlled safety valve design is its greatest advantage . In the simplest system an SCSSV is held open by hydraulic pressure supplied by a manifold at the surface, the pressure being maintained by hydraulic pumps controlled by a pressure pilot installed at some strategic point at the wellhead. Damage to the wellhead or flowlines causes a pressure monitor pilot to exhaust pneumatic pressure from a low pressure line which in turn causes a relay to block control pressure to a 3-way hydraulic controller resulting in hydraulic pressure loss in the SCSSV control line.When this pressure is lost, the safety valve automatically closes, shutting off all flow from the tubing. There are two main categories of SCSSVs: • •

Wireline Retrievable SCSSV. Tubing Retrievable SCSSV.

SCSSVs utilise the ball or flapper type closure mechanisms. Both categories are supplied with or without internal equalising features. This allows the pressure to equalise across the valve so as it can be re-opened. Valves without this feature need to be equalised by pressure applied at surface. The former is more prone to failure due to having more operating parts whereas for the latter equalisation pressure is often difficult to provide and possibly time consuming. a) Wireline Retrievable SCSSV Wireline retrievable sub-surface safety valves are located and locked, using standard wireline methods, in a dedicated safety valve landing nipple (SVLN). The SVLN is connected to a hydraulic control line pressure source at the surface normally by a 1/4 ins. OD stainless steel tubing. When the safety valve is set in the nipple, the packing section seals against the bore of the nipple below the port.The packing section of the lock mandrel forms a seal above the port in the nipple. Control pressure, introduced through the control line, enters the valve through the port in the housing and allows pressure to be applied to open the valve. Figure 1.34 shows a typical surface-controlled, wireline retrievable safety valve. 1-60


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Top Sub for Installation of Lock mandrel c/w Upper Packing Set Valve Assembly

Hydraulic Control Line

Hydraulic Port

Lock Mandrel

Piston Packing Stack

Packing Sack Safety Valve Landing Nipple

Spring

Packing Stack Piston

Power Spring Secondary Valve Seat Equalisation Port

Primary Valve Seat with Ball

Secondary Valve Seat

Ball Seat Ball

Figure 1.34 - Typical Wireline Retrievable SCSSV (WRSV) and Installation


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Because a wireline retrievable SCSSV seats in a landing nipple installed in the production string, it offers a much smaller bore than a tubing retrievable SCSSV for the same size of tubing. Frequently, WRSVs have to be pulled prior to wireline operations being carried out. Compared to a tubing retrievable SCSSV, the wireline retrievable SCSSV is easy to replace in the case of failure. Most failures can be prevented by introducing a planned maintenance schedule in which valves are regularly pulled and serviced. However, during wireline entry operations there is also a safety risk and care must be maintained at all times. The components required for the installation of a wireline retrievable SCSSV are: • • • • • • •

Hydraulic control line. Control Line Protectors. Hydraulic control manifold. Wireline retrievable safety valve. Safety valve landing nipple. Locking Mandrel. Wireline installation and retrieval tools for the locking mandrel.

b) Tubing Retrievable SCSSV Tubing retrievable safety valves operate by the same principle as wireline SCSSVs except all the components are incorporated in one assembly which is installed in the completion string; See Figure 1.35. Some models have rod pistons instead of the more normal concentric piston designs. Should the tubing retrievable valve need to be locked out, a wireline retrievable can be installed and operated, although with a reduced internal bore. The components required are: • • • •

Hydraulic control line. Control line protectors. Hydraulic Control Manifold. Tubing retrievable safety valve.

and additionally for insert capability: • • • •

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Wireline safety valve. Locking mandrel. Wireline installation and retrieval tools for the locking mandrel. Lock-out tool for the tubing retrievable valve.


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Hydraulic Port Tubing Connection

Hydraulic Port Hydraulic Line

Metal Seat (Upper Static Seal)

Upper Piston Assembly

Rod Piston (Upper Assembly)

Opposing Metal Cups (Dynamic Seals) Rod Piston (Lower Assembly)

Lower Piston Assembly Flow Tube b) Open Position

Hydraulic Port Metal Seal (Lower Static Seal) Upper Piston Assembly Power Spring

Flow Tube

Flapper Spring Flapper Lower Piston Assembly Spring Loaded Debris Barrier

Flow Tube

a) TRDP-5 TRSV

Power Spring c) Closed Position

Figure 1.35 - Typical Tubing Retrievable SCSSV (TRSV)


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Safety Valve Leak Testing A test performed on Sub-Surface Safety Valves immediately after installation, and on a regular schedule, is the leak test. A typical leak test entails the production, kill and swab valves are closed on the Xmas tree and control line pressure bled off to close the valve. Tubing pressure is bled off slowly above the valve to zero for a tubing retrievable valve and in 100 psi. (6.9 bar) stages for a wireline retrievable valve. The system is closed in again and tubing pressure monitored. If there is a rapid build up, a major leak is indicated or improper functioning of the valve; in this case the valve should be cycled and the test repeated. After a specified shut-in period the tubing head pressure should be below a maximum allowable pressure as specified by the operator’s leak off criteria although there is an API standard. NOTE:

It is extremely important that pressure data is fully and accurately recorded.

After initial installation, leak tests should be carried out periodically; this accomplishes three functions: 1. To test the integrity of the seal in the safety valve. 2. To test that the lock mandrel in a wireline retrievable valve is still properly locked. 3. To cycle the valve to prevent ‘freezing’ in wells where they have been sitting in either fully open or fully closed position for extended periods of time. NOTE:

All the above tests should be conducted on all Sub-Surface Safety Valves by authorised personnel.

a) API Leakage Limit in Gas Wells For gas wells, leakage rates can be compiled from a surface pressure build-up from the formula (low pressure application) 4(∆p)V Q = ––––– ∆t where: Q ∆t V ∆p

Is the leakage rate (in standard cubic ft/hr.) Is the build-up time in minutes to reach a stabilised pressure Is the volume of the tubing string above the SSSV (ft3) Is the change in pressure (psi.)

If the leakage rate is in excess of 900 SCft./hr. (25.5 m3/hr.), the SCSSV should be cycled opened and re-tested. If the leakage rate is greater than API or Group specifications, which ever is the most stringent, then corrective action must be taken.

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b) API Leakage limit - Oil Wells For oil wells, the pressure depends on the static fluid level and the amount of gas in the oil. If the liquid level is below the SCSSV, the formula for gas wells can be used. If the liquid level is above the SCSSV then the leakage rates are determined from the build-up of surface pressure which is converted to a liquid volume. If the leakage rate is in excess of 6.3 gal/hr (0.4 m3/min) then the SCSSV should be cycled and re-tested. If the leakage rate is still in excess of 6.3 gal/hr (0.4 m3/min) then corrective action should be taken. 1.3.13 Annulus Safety Valves The sub-surface safety valves discussed so far, i.e. tubing retrievable and wireline retrievable, only provide tubing flow control. In these systems, no annular flow control exists. Annulus safety valve systems are usually associated with completions where artificial lift or secondary recovery methods are employed e.g. gas venting in electric submersible pump (ESP), hydraulic pump, and gas lift installations. There application is to remove the potential hazard of a large gas escape in the event there is an incident where the tubing hanger seal is breached. There are a number of designs of such systems on the market and the variety of mode of operation is too wide to be covered in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off.This is generally a packer but may also be a casing polished bore nipple in some designs into which a packing mandrel will seal. In the sealing device there is a valve mechanism operated by hydraulic pressure similarly to an SCSSV. The valve mechanism opens the communication path from the annulus below to the annulus above the valve and is fail safe closed. The closure mechanism may be a sliding sleeve, poppet or flapper device. Figure 1.30 shows a typical annulus safety valve.


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Tubing Hanger

Production Casing

Hydraulic Connection

Baker Multi-Purpose Expansion Joint

Annulus Port Tubing Valve TRSV Hydraulic Control Line Flow Coupling

Power Spring

Tubing Retrievable SCSSV

Flow Coupling

Spacer Baker "AVLDEM" Annulus Safety Valve

Baker "FLX-2" Pack-Off Tubing Anchor c/w Concentric Tubing Anchor

Figure 1.36 - Typical Annulus Type Safety Valve System 1-66


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1.3.14 Surface Control Manifolds Surface control manifolds are designed to provide and control the hydraulic pressure required to hold an SCSSV open. The manifold has one or more air powered hydraulic pumps to maintain the hydraulic operating pressure for the safety valve. The hydraulic pressure is through a 3-way control valve which is controlled by remote pressure pilots and fire sensors. Pilot, sensor or manual activation removes the hydraulic pressure, closing the safety valve. NOTE:

Activation can occur from the operation of remote-control pressure sensing pilots, fusible plugs, plastic line, sand probes, level controllers or emergency shut down (ESD) systems.

Surface control manifolds are generally supplied as complete systems containing a reservoir, pressure control regulators, relief valves, gauges, and a pump with manual override. Manifolds, in combination with the various pilot monitors, have many different applications, e.g. controlling multiple wells using individual control, multiple wells using individual pressures and any combination of these. Other additional features have been incorporated into surface control manifolds when the system is integrated with other pressure operated devices. A control panel, designed to supply hydraulic pressure to a surface safety valve (SSV) and hydraulic pressure to an SCSSV, contains a circuit logic for proper sequential opening and closing of the safety valves, i.e. •

Sequential closing: - SSV first - SCSSV second.

•

Sequential re-opening: - SCSSV first - SSV second.

Sequential logic is incorporated to increase the service life of hydraulic master valves and SCSSVs to prevent SCSSVs becoming flow cut by high velocity wells. Improvements have also been made in the monitoring systems, e.g. • •

Sand erosion probes installed on a flowline to monitor sand flow production. Quick exhaust valves which allow rapid exhausting of control line pressure to speed up valve closures.


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1.3.15 Control Lines The conduit which supplies the hydraulic fluid to the SCSSV is the control line. The control line is normally a 1/4 ins. OD tubing attached to the sub-surface valve (TRSV) or nipple (WRSV) with a compression fitting, and run up the outside of the tubing to the tubing hanger. The method of termination at the hanger is dependent on the type wellhead and hanger system being deployed. Some control lines on land wells are simply fed out through a packing element in a port (often a tie-down bolt hole) which is tightened to seal around the tubing. Other systems have drilled ports in the hanger, into which the control line is fitted again with a compression fitting, and the spool sealed off from the annulus and the Xmas tree bore by concentric weight set or pressure energised seals. Subsea wellheads have different methods of termination so the tree can be installed subsea without diver assistance. The control line material is selected to meet the environment into which it is to be installed and be compatible with both the safety valve and the hanger materials from the point of corrosion due to being of dissimilar materials.Their is a large choice of control lines materials from 316 ss for sweet service to Inconel and Elgiloy alloys for more demanding service.They are also supplied in hard durable plastic coatings for added protection from corrosion and against crushing damage during installation which at one time was one of the major problems during completing. Two lines can be encased for dual control line safety valves. Control lines are held flat to the tubing by control line protectors usually placed across a coupling or connection and sometimes also in the middle of a joint. The protector has a slot into which the control line plastic outer coating fits. Simple banding can be used but it is not strong and is easily ripped off. Protectors are now metal clamp types as earlier rubber versions were easier detached and caused major problems while retrieving the completion string. 1.3.16 Tubing The purpose of using tubing in a well is to convey the product from the producing zone to the surface, or in some cases to convey fluids from the surface to the producing zone. It should continue to do this effectively, safely and economically for the life of the well, so care must be taken in its selection, protection and installation. Tubulars up to and including 41/2 ins. are classified as tubing, over 41/2 ins. is casing. In large capacity wells, casing size tubulars may be run as the production conduit. Tubing selection is governed by several factors. Anticipated well peak production rate, depth of well, casing sizes, well product, use of wireline tools and equipment, pressures, temperatures, and tubing/annulus differential pressures are among those which must be considered.

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To meet various completion designs, there is a wide range of tubing sizes, wall thickness (weights) and materials to provide resistance to tubing forces and differing well environments. The best tubing selection is the cheapest tubing which will meet the external, internal and longitudinal forces it will be subjected to, and resist all corrosive fluids in the well product. This is not practical in every instance and often compromises have to be made. For ease of identification, tubing is colour coded to API specification. Some specialist suppliers steels are not covered by the code and provide their own codes. Refer to codes to ensure the tubing is according to requirements. 1.3.17 Tubing Hangers a)

Bowl Type Tubing Head/Mandrel Type Tubing Hanger

A Tubing Head/Tubing Hanger combination unit is attached to the uppermost casing head on the wellhead. The main functions of this unit are to: • • • • •

suspend the tubing seal the annular space between the tubing and the casing lock the tubing hanger in place provide a base for the wellhead top assembly (Xmas Tree) provide access to the annular space (‘A’ annulus).

Suspension of the tubing is accomplished usually by threads, slips or any other suitable device i.e.. rams. The tubing head consists of a spool piece type housing where the internal profile of the top section is a straight or tapered cylindrical receptacle (bowl) into which the tubing hanger is landed, suspending the tubing and sealing off the volume between the tubing and the casing. A tapered type tubing hanger system is shown in Figure 1.37 The important features of tubing hangers are: Top and Bottom Connections

The size and pressure ratings of these connections (usually flanged) must be compatible with the size and pressure rating of the joining connections.

Upper Bowl

Provides the seal area for various tubing hangers and a load shoulder to support the production tubing.

Lower Bowl

This is provided to house some type of isolation seal.


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Set Screws

Set screws or hold-down screws are found in most tubing heads and have two important functions. • retain the tubing hanger and prevent any upward tubing movement due to pressure surges. • activate (energise) the body seals on the tubing hanger.

Outlets

These provide access to the annulus (e.g.. for pressure monitoring or gas lift) during production.

Test Port

Permits the pressure testing of the hanger seal assembly, lockdown screw packing connection between flanges, and the secondary (isolation) seal.

Landing Threads

These are the uppermost threads on the hanger and they must support the entire weight of the tubing string.

Bottom Threads

These must support the entire weight of the tubing string and seal the producing zone from the annulus.

Sealing Area

These provide compression type sealing between the outside diameter of the hanger body and the inside diameter of the hanger bowl. Sealing is accomplished by energising elastomer seals or metal-to-metal seals by the action of tubing weight on various load bearing surfaces.

Tubing hangers are sized according to the upper bowl of the tubing head and the tubing size the hanger will be supporting. Thus, a 7" x 27/8" tubing hanger means a 27/8" production string suspended from a tubing head 71/16" top bowl.

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Figure 1.37- Cameron ‘F’ Tubing Head and Hangers © ABERDEEN DRILLING SCHOOLS 2002

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b) Ram Type Tubing Head Ram Type Tubing Heads find their application in completions where manipulation of the tubing is necessary to locate and latch into a packer and to maintain tension in the tubing when landed. Figure 1. 38 shows a ram type tubing head which comprises a housing with two side outlets in which are located retractable rams. These rams, when closed, support the hanger nipple which is screwed on to the top of the tubing string. The seal between the annulus and the tubing is provided by a seal assembly which is located around the hanger nipple above the rams. With the ram type tubing hanger installed on the wellhead and the packer set, production tubing is run and spaced out so that the final position of the hanger nipple is that distance below the tubing head corresponding to the amount of stretch required to give the appropriate tension. The tubing is latched into the packer and tension applied to the tubing so that the hanger nipple is just above its final hang off position. The rams are closed, the tubing weight is set on the rams and the handling string removed. The seal assembly is then installed, bolted down, and the seal system energised by the injection of plastic packing. Finally, the BOPs are removed and the Xmas Tree installed. NOTE:

Like mandrel type hangers, landing nipple hangers are provided with a top thread for the landing joint, an internal left hand thread or wireline profile for the installation of a back pressure valve, and can be supplied with extended necks to facilitate secondary sealing.Also, ram type tubing heads are available with control line outlets to allow an SCSSV to be incorporated in the tubing string.

The disadvantages of ram type tubing hangers are: • • •

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After long service periods, it may be difficult to re-open the rams The tubing pick-up weight must be overcome prior to opening the rams otherwise the rams will be difficult to open They are bulky, heavy and expensive.


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HANGER NIPPLE HANGER SEALS

RETRACTABLE RAM

Figure 1.38 - Cameron Single Ram Tubing Head (‘SRT’)


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c) Multiple Tubing Heads/Hangers The purpose of a multiple completion is to produce reservoirs simultaneously without any pressure or reservoir fluid combining during the transfer of fluid from the production zones to the production facilities. For multiple string completions two or three segments, one for each production string, are used to form a hanger assembly which, when installed in the appropriate tubing head, resembles a mandrel type tubing hanger. Figure 1.39 shows a tubing head/hanger arrangement for use in a dual completion. An important characteristic of this tubing head is the support wedges (or in other heads support pins) used to guide and align the two segmented hangers in their proper positions in the upper bowl. The segmented hangers are locked in place with the tiedown screws. A disadvantage of this type of hanger is that seals are often damaged while installing the second segment. NOTE:

Segmented hangers are available to accommodate a back pressure valve and are also manufactured with control line outlets to allow an SCSSV to be installed in the production tubing.

Figure 1.39- Multiple Tubing Heads/Hangers

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1.3.18 Wellheads At the drilling stage, casing is run and cemented in a well to line the well to protect against collapse of the borehole, to prevent unwanted leakage into or from rock formations and to provide a concentric bore for future operations.Various strings of casing are run, i.e. conductor, surface string (which provides a base for the wellhead) followed by one or more intermediate strings depending on the target depth and expected conditions in the well. At the completion stage, production tubing is run to act as a flowline between the formation and surface. Unlike casing, production tubing is not cemented in the hole so the entire tubing weight must be supported by a suspension system suitably installed in a tubing head. The tubing head is positioned on top of the uppermost casing head of a well and is used to suspend the production tubing and to produce an effective seal between tubing and casing. Tubing heads are composed of a body, a hanger-sealing device (tubing hanger), and a mechanism which retains the hanger. The wellhead equipment installed on top of the tubing head serves to control and direct the flow of well fluids from the production tubing string. Such surface equipment may range from a simple flow cross with stuffing box to an elaborate Xmas tree. Choice of surface tree depends on well fluid production method (natural flow or artificial) and the wellhead pressure encountered. In general, most surface trees are comprised of at least one master valve, at least two wing or flow valves (one of which may be hydraulically operated), and one swab valve utilised in wireline operations; See Figure 1.40. Wellhead equipment (spools, valves, chokes) is either screwed, flanged or a combination of both.Wellheads with screwed connections are used for pressures not exceeding 1,000 psi. (69 bar); those with screwed valves and chokes not exceeding 5,000 psi. (345 bar). However, most operators specify, even for low pressure wellheads, flanged connections since they are less susceptible to leakage, easier to orientate and, especially in the larger sizes, easier to manipulate. With regard to subsea wellheads, there is no API standard and manufacturers all have their own specific designs which includes some means of orientation in order to align the subsea tree inlets and outlets to the flowlines or indeed in a subsea manifolding system.


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Figure 1.40 - Typical Surface Xmas Tree

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Xmas Trees An Xmas Tree is an assembly of valves and fittings used to control the flow of tubing fluids at surface and to provide access to the production tubing and on some subsea completions to the annulus string. In general, an Xmas Tree is essentially a manifold of valves which is installed as a unit on top of a tubing head or subsea wellhead. Similarly to the tubing hanger the range of trees available is wide and are not all addressed in this manual. However the valving of surface Xmas trees is similar throughout and typically contains the following valves and tree cap: Lower Master Gate Valve (LMG) The Lower Master Valve is utilised on all Xmas trees to shut in a well. This valve is usually operated manually. As its name implies, the master is the most important valve on the Xmas tree. When closed, this valve should keep the well pressure under full control and therefore should be in optimum condition - it should never be used as a working valve. In moderate to high pressure wells, Xmas trees are often furnished with a valve actuator system for automatic or remote controlled operation (i.e. surface safety valve system). This is often a regulatory requirement in sour gas or high pressure wells. Upper Master Gate Valve (UMG) The Upper Master Valve is used on moderate to high pressure wells as a emergency shut-in system where the valve should be capable of cutting at least 72/3 ins. braided wireline. This valve can be actuated pneumatically or hydraulically. The UMG valve is a surface safety valve and is normally connected to an emergency shut-down (ESD) system. Flow Wing Valve (FWV) The Flow Wing Valve permits the passage of well fluids to the choke valve. This valve can be operated manually or automatically (pneumatic or hydraulic) depending on whether a surface safety system is to be included in the production wing design. Choke Valve The Choke Valve is used to restrict, control or regulate the flow of hydrocarbons to the production facilities.This valve is operated manually or automatically and may be of the fixed (positive) or adjustable type. It is the only valve on the Xmas tree that is used to control flow. NOTE:

All other valves used on Xmas trees are invariably of the gate valve type providing full bore access to the well, that is, such valves must be operated to the fully open or closed position.


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Kill Wing Valve The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure equalisation across tree valves e.g. during wireline operations or prior to the removal/opening of a sub-surface safety valve. This valve is usually manually operated. Swab Valve The Swab Valve permits vertical entry into the well for wireline (e.g. running BHP/BHT gauges, tubing conditioning) or for well interventions such as coiled tubing operations and logging. This valve is operated manually. Xmas Tree Cap The Xmas Tree Cap provides the appropriate connection for well control equipment when conducting well interventions and is installed directly above the swab valve. The Xmas Tree cap normally includes a quick union type connection and should be strong enough to support the well control equipment.The bore of the cap flange should be compatible with the tree and permit the running of service tools. Sometimes the Cap is removed and replaced by tertiary well control equipment.

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2.1

GENERAL

2.2

BARRIER THEORY

2.3


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2. WELL CONTROL METHODS 2.1 GENERAL This section illustrates the various well control methods and practices employed on all the various well intervention servicing methods and includes a section to explain barrier theory. The most significance between the various types of well service methods is whether they are live well or dead well interventions as this impacts specifically on the equipment and methods of well control employed. Dead well interventions, in terms of the IWCF, are classified as workovers and well control methods for these are covered in the IWCF drilling test. The methods are addressed in this course are those used specifically in live well interventions. There is a distinct difference between the terminology used between well control used in rig workover operations and that in live well interventions. Workover well control uses a combination of barriers and procedures in a systematic method to contain pressure downhole whereas live well interventions use a system of barriers to contain pressure at surface. Barrier theory and these systems are described in the following sections.


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IWCF WELL INTERVENTION PRESSURE CONTROL WELL CONTROL METHODS

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2.2 BARRIER THEORY Definition: A Barrier is any device, fluid or substance that prevents the flow of well bore fluids. There are two types of barriers: • •

Mechanical. Hydrostatic.

A rule common to well intervention activities worldwide regarding pressure control is that a minimum of two independent and tested barriers shall be available at all times. In any circumstance where either of the barriers has failed, or there are indications that it is likely to fail, immediate action must be taken to re-instate or supplement that barrier and returning the well to double barrier protection again. The ‘primary barrier’ is the term used to described the first line system of pressure containment and ‘secondary barrier’ the next line of defence. Nowadays, it is common, especially of high pressure wells, to install a third line of defence or a ‘tertiary’ barrier. The particular status of the well will have different barriers in place for given operations and well circumstances. For instance, the completion provides barriers in the form of individual Xmas tree valves and a sub-surface safety valve, however, when running coiled tubing, these cannot be closed and therefore are not available barriers until the BHA is above them. The function of well control in well interventions, is the arrangement of the barriers into groups and their systematic operation to provide competent well control. As stated earlier, these are conveniently arranged into three main categories of pressure control, namely: • • •

Primary. Secondary. Tertiary.

Each of these consist of at least one, or a combination of mechanical barriers described below. NOTE:

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These categories may not be the terms used in some areas of the world, especially where the common language is not English.


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2.2.1 Mechanical Barriers Mechanical barriers can be either closed barrier systems such as a wireline lubricator system complete with a stuffing box, i.e. the complete surface pressure envelope or closeable barrier systems which are held open to allow well entry but available and ready to be closed at any time on demand.Various types of closed and closeable barriers are listed below. Types of closed barriers typically are: • • • • •

Wireline stuffing box (or grease control head)/lubricator/riser pressure envelopes. Coiled Tubing stripper/riser pressure envelops. Snubbing strippers (or annular preventers)/riser pressure envelopes. Coiled tubing check valves. Snubbing work string check valves.(Back pressure valves)

Types of closeable barriers are: • • • • •

BOP rams. Xmas tree valves. Subsurface safety valves. * Shear/seal valves/BOPs. Annular preventers.

Additional barriers can be installed downhole, either as a back up to a failed primary or secondary barrier or to allow removal of the Xmas tree for repair or for installation of workover BOPs. These barriers may be: • • • • •

Wireline plugs. Bridge plugs. Cement plugs. Ice plugs. Overbalance hydrostatic fluid.

*

Sub-surface safety valves are acceptable as barriers during normal operations if they are tested in accordance with the test criteria given below, however, to be used for well plugging, i.e. for Xmas tree removal before a rig operation, it must be leaktight.


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Common Barrier Definitions Some other commonly used barrier definitions are given below: Leaktight Failsafe Fail to Test Fail to Close Positive Plug

No observable flow or pressure change. A device which returns to the closed position on loss of the control function. Failure of a barrier to meet test criteria. Inability of a device to move to the closed position. Holds pressure from above and below.

Barrier Integrity Mechanical barriers must be tested, preferably from the direction of anticipated flow.Tests on closed type barriers should be leaktight. The leakage rate on closeable barriers such as Xmas tree valves etc. should be the API leakage criteria: 400 cc/min or 900 scf/hr with the exception of sub-surface safety valves used in well plugging (refer to note above in list of closeable barriers). Each operator should develop procedures for testing of Xmas tree and sub-surface safety valves to meet this criteria. This is problematic in subsea completions where there are long undulating production flowlines and riser systems which makes it difficult to calculate leakage rates for various well GORs and downstream volumes; however to help, formulae are provided in API 14A. 2.2.2 Hydrostatic Barriers Hydrostatic barriers are provided by liquids. A liquid is only a barrier when the hydrostatic head of pressure is greater than the formation pore pressure at the top of the producing interval and when the fluid level and condition (i.e. weight) can be monitored. The specific gravity of the fluid to be used as a barrier may be difficult to predict without good formation pressure data.The hydrostatic overbalance provided should be circa 200 psi. but may be adjusted to counter for high losses in wells which cannot support this differential, especially troublesome when using solids free brines. A fluid can only be confirmed as a barrier after diligent monitoring of the well over a specified period of time, to ensure that any thermal expansion contraction effects have ceased. Typical fluid barriers are: • • • •

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Drilling muds. Completion brines. Seawater. Fresh water.


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2.2.3 Primary Pressure Control Primary pressure control is the system which provides the first line of defence from an uncontrolled well flow. In each of the well servicing intervention methods it is provided by different mechanical systems. On a wireline rig up it is simply the stuffing box and lubricator envelop, however on a C/T or snubbing rig up, it consists of the riser pressure envelop and internal workstring check valves. 2.2.4 Secondary Pressure Control Secondary pressure control is the system which provides the second line of defence in the event that primary well control cannot be properly maintained. This is generally provided by the BOP system . If pumping facilities are available, although undesirable, a hydostatic fluid barrier can be placed in the wellbore as a secondary barrier when either the primary or original secondary barrier has failed and there is no tertiary barrier. 2.2.5 Tertiary Pressure Control Tertiary pressure control is not always available but may be an additional third and final line of defence in the event that secondary well control cannot be properly maintained.This is usually a shear seal valve or BOP system.This may be an integral part of the Xmas tree (e.g. a wireline or coiled tubing cutting actuator), or installed directly on top of the tree immediately before operations commence.


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2.3 WELL INTERVENTION PRESSURE CONTROL The method of pressure control on live wells with wireline, coiled tubing or snubbing services methods, is provided by primary, secondary and occasionally tertiary barrier systems as outlined above. In live well interventions, it is not generally necessary to provide kill facilities unless there is higher risk due extreme high pressure or the presence of high concentrations of H2S. In many applications, pumping services may be on hand for other operations such as well clean-outs and stimulations and may double as a kill facility provided there is a suitable supply of kill fluid and a handling system. 2.3.1 Wireline Slickline Wireline relies entirely on the lubricator system to provide primary pressure control. Secondary pressure control is provided by the wireline BOPs and tertiary well control may be available in the form of another wireline cutting valve, either contained in the Xmas tree or as a shear/ seal valve or BOP installed on top of the Xmas tree. The various pressure control barrier systems are: Primary • • •

Stuffing box and lubricator system. Check valve if the wireline breaks and is ejected from the lubricator. Xmas tree valves when installing into,or removing tools from, the lubricator

Secondary • • •

Wireline BOP rams/valve which can close and seal around the wire. Xmas tree upper master, if the wire is broken and ejected. SCSSV, if wire is above it.

The BOP rams can be used for stripping wire out of a well but only when absolutely necessary. Stripping through the BOPs is only carried out to find the free end of the wire for wireline recovery. Tertiary • •

Wireline cutting valve/BOP. Xmas tree valve, if absolutely necessary.

In the event of primary and secondary failure with no tertiary barriers available, a Xmas tree valve can be used to sever the wire, as they can easily cut wireline although the valve seat may be damaged. The valve used should be the upper master for two reasons:

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If the lower master is used and damaged, it requires the well to be plugged before repair. If the swab is used and damaged the well cannot be used for production as there is no longer double barrier protection from the production fluid.

Braided Line The system for braided line is very similar to slickline. Pressure control is provided by: Primary • • •

Grease seal and lubricator system. Check valve if the wire breaks and is ejected from the lubricator. Xmas tree valves when installing into,or removing tools from, the riser.

Secondary Two wireline BOP rams (in conjunction with a grease pump) which can close and seal around the wire. • •

Xmas tree upper master, if the wire is broken and ejected. SCSSV, if wire is above it.

Tertiary • •

Wireline cutting valve. Shear/seal valve or BOP installed directly onto the top of the Xmas tree.

In general, tertiary barriers are rarely used unless a heavy duty wireline operation is being carried out.


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2.3.2 Coiled Tubing Coiled tubing well control equipment is similar to wireline but also includes internal workstring barrier systems. External pressure control is provided by: Primary • •

Stripper. Xmas tree valves when installing into,or removing tools from, the riser.

Secondary • •

BOPs . SCSSV, if the tubing is not straddling it.

Tertiary •

Shear/seal BOP mounted directly on top of the Xmas tree.

Internal pressure control is provided by: Primary •

Two check valves in the BHA.

Secondary •

BOPs .

Tertiary •

Shear/seal BOP mounted directly on top of the Xmas tree.

In the North Sea Region, it has almost become obligatory to use shear/seal BOPs due to a number of instances where the up-to-then commonly used primary and secondary barrier systems failed to deal with some well control occurrences. NOTE:

2-8

Some well interventions are conducted without BHA check valves as it is necessary to reverse circulate. In these cases the primary inside well control is the BOP shear rams and a shear/seal BOP becomes the secondary.


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2.3.3 Snubbing There are two types of snubbing BOP set-ups, one for running upset pipe and one for nonupset or tapered upset tubing connections (i.e. not square shouldered); Pressure control is provided by: External pressure control is provided by: Primary •

Stripper BOPs, stripper rubber or annular preventer.

Secondary • •

Two safety (pipe) BOP rams. SCSSV, if pipe is above it.

Tertiary •

BOP shear and blind rams or a shear/seal valve or BOP mounted directly on top of the Xmas tree.

Internal pressure control is provided by: Primary •

Two check valves in the BHA.

Secondary •

Wireline plug installed by wireline in the BHA or an additional third check valve.

Tertiary • •

A shear/seal valve or BOP mounted directly on top of the Xmas tree. Kill pump facility to install a barite or cement plug.


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3.

REASONS FOR WELL INTERVENTION

3.1

GENERAL

3.2

TUBING BLOCKING

3.3

CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION

3.4

MECHANICAL FAILURE

3.5

STIMULATION OF LOW PRODUCTIVITY WELLS

3.6

PARTIALLY DEPLETED RESERVOIRS

3.7

SAND CONTROL

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3. REASONS FOR WELL INTERVENTIONS 3.1 GENERAL Many servicing operations can be conducted by rig workovers, however live well intervention is preferred as killing a well risks fluid invasion of the formation thereby causing potential formation damage. The primary objective of well intervention operations is the management of wells to provide optimum well production. This is achieved by conducting live well remedial operations, obtaining downhole reservoir data or preparation of the well for a dead well workover (if a problem cannot be solved by live well servicing). Occasionally, gathering of downhole reservoir data is a secondary objective only opportunistically taken when a an intervention is planned for other reasons. This data are usually to provide well information on lateral and vertical movement, current location of oil, water and gas and identifying the producing the zones. There are many reasons for remedial live well intervention well operations, most notably to: • • • • • • • • •

Remove obstructions to flow such as tubing blockage with sand, wax or asphalt. Eliminate excessive water or gas production. Repair mechanical failure. Improve production through well stimulation, re-completions or multiple completions on low productivity wells. Enhance production by conducting well stimulation such as hydraulic fractures on high productivity wells. Increase production by bringing other additional potentially productive zones on stream. Maintain control of oil, water and gas in various zones or layers in stratified reservoirs. Side-tracking passed severely damaged formations. Increase production by drilling laterals.

Before a well is entered, a complete analysis must be made of the current well status, the reasons for work carefully established, the associated risks identified and appropriate contingencies measures planned in the event of operational failure. All oil and gas wells will encounter some impairment to production during it’s producing life and well service operations will need to be planned to rectify or improve the conditions within the well. Therefore, common servicing operations such as cleaning out fill, reperforating, chemical treating, acidising, fracturing or a combination of these techniques are routinely carried out to enhance production. A description of these main well problems are discussed in the following sections.


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3.2 TUBING BLOCKAGE Tubing blockage is generally caused by sand, wax and asphalt production or scale build up. It can usually be remedied with a well clean out operation. Some of these can be prevented, or at least alleviated, by treating the formation with regular chemical inhibition treatments, pumped into the formation from surface. With regard to injection wells severe formation scaling can occur if injection water is not treated so that it is compatible with the formation fluids. Tubing blockage is one of the most commonly experienced production problems and which is remedied by clean out operations conducted normally by snubbing or coiled tubing (C/T) intervention although dead well workover may also be considered.The use of snubbing or C/ T is more desirable as they can be carried out without killing the well. C/T is preferred as it is relatively low cost, is easily organised and very effective when used in conjunction with modern jetting or clean-out tools (especially with the larger C/T sizes which allow higher pump rates). In most circumstances, flowing the well helps with the efficiency of the clean out. Wax build-up can be removed by an operation termed ‘Hot Oiling’.This is a simple treatment consisting of pumping heated oil from surface at a temperature sufficiently high enough to melt the wax. This can also be done by circulation of the hot oil through C/T which is preferred as it prevents any fluids being pumped to the formation.Asphalt can also be removed similarly by pumping solvents rather than hot oil. Some well clean outs may be accomplished with wireline methods using tools such as gauge cutters which can remove wax from tubing walls and bailing to remove sand or other blockages, provided the amount to be removed is relatively small. It is often easier to use wireline, even if it may be less efficient, as many platforms are already equipped with permanent wireline units or they can be easily mobilised. C/T takes longer to rig up and deploy which are considerations which need to be taken into account during the evaluation process. However in general, most operations can more efficiently be accomplished using C/T and it is sometimes the only option if the well is high angle or horizontal.The general limit for wireline operations is circa 70˚ from vertical but this may vary according to well build up angles and the types of tools to be run. Snubbing with a Hydraulic Workover unit (HWO) may also be considered but it is generally not utilised as it is slow and costly in comparison with C/T. However, in some circumstances, e.g. where there is not enough space for a C/T injector or the reel due to their size, Hydraulic Workover may be the only alternative.

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3.3 CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION As an oil zone is depleted, the gas/oil or water/oil interfaces will move vertically in the formation. This may result in increasing undesired water or gas production. Excessive gas production leads to a premature decrease in reservoir pressure, hence reducing the energy available to move the oil into the well bore and ultimately reduces the quantity of gas necessary to lift the oil to surface. When excessive water is produced, it leads to reduced oil production due to; the increased hydrostatic head in the tubing acting against the formation pressure, increased risk of corrosion and production problems handling and disposing of the water. It may also cause sand production which can lead to erosion of completion and production equipment. These problems can be controlled by the appropriate well intervention measures, as described below. 3.3.1 Control Of Water Production There are different reasons for water problems. Firstly, fingering of water in stratified or layered reservoirs where the water production is essentially from one zone. Secondly, advancing water level due to oil depletion.Thirdly; water coning in reservoirs where there is appreciable vertical permeability; See Figure 3.1, Figure 3.2 and Figure 3.3. Once a rock becomes more saturated with water, the relatively permeability to water increases in regard to that of the other fluids. This leads to a self aggravating cycle of increasing water flow and increasing relative permeability to water. Prior to running or planning operations for water control, production logs must be run which will identify the zones from which water is being produced. Once identified, this can usually be controlled by a number of differing methods depending upon the specific well design and well conditions: • • • •

Sand placement in the sump. Setting a through tubing bridge plug. Cement squeezing. Chemical treatment to produce a gel block.

Sand placement in the sump may solve the problem in circumstances where there is a sufficient height of sand as the vertical permeability of a column of sand is high and blocks water flow. Cement squeezes have probably been the commonest means of plugging off water producing zones in the past utilising workover methods requiring killing of the well, pulling the completion, cementing and re-completing.


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High production liner or monobore type completions have been specifically designed for through tubing operations enabling water control by simply installing a through tubing bridge plug by wireline or C/T after which cement can be squeezed, if necessary. Cement squeezing by C/T below regular packer style completions using modern through tubing tooling, is now also common practice. Water blocking by creating a gel in the formation is a much more recent development. This entails pumping chemicals to the formation which react after a pre-determined period of time to form a gel. The viscosity of the gel is so high that it will not flow through the formation pores, blocking the flow of water trapped behind the gel. This method is usually expensive due to high chemical costs. Plugging back of water producing zones may on occasions require the well to be re-completed if the packer has to be moved or if shallower zones need to be perforated and brought on stream.

Well Bore

Low Permeability

High Permeability Water Intermediate Permeability

Low Permeability

Figure 3.1 - Water Fingering Due to Heterogeneities

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Initial Conditions

Higher Oil/Water Contact Later In Production

Water Cut Becomes Severe

Figure 3.2 - Advancing Oil/Water Contact

Producing Oil/Water Contact Resulting From Coning

Oil

Original Oil/Water Contact

Water

Figure 3.3 - Water Production by Coning


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3.3.2 Control Of Gas Production The most common reason for excessive gas production is the growth of the gas cap as oil is produced; See Figure 3.4.A gas/oil contact will gradually move downwards causing an increase in the production of gas. The common method of remedying excessive gas coning is to squeeze the gas producing zone and deepen the well by re-perforating (converse to water coning). An alternative, is to conduct a workover where the well is plugged back and side-tracked with the new hole drilled horizontally through the lower part of the reservoir avoiding the gas cap. In a layered reservoir, gas producing zones can also usually be effectively squeezed off with cement.Again, most cement squeezes can be accomplished with C/T methods using throughtubing tools. Initial Conditions

Gas Cap Is Growing

High GOR Is Produced

Figure 3.4 - Increasing Gas Cap During Oil Production

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3.4 MECHANICAL FAILURE Well service operations to repair mechanical completion failures are still relatively common in old wells, however in new wells less servicing is required due to the increasing reliability of modern completion equipment. In the past, one of the most common reasons for working over a well was to replace downhole safety valves which had failed. For this reason, engineers were inclined to install wireline retrievable valves as they could easily be replaced using live well interventions by wireline methods, hence avoiding the need to pull tubing. Nowadays, this is no longer the case as the reliability of tubing retrievable valves has increased substantially where it is now the most commonly used valve. Probably the most common reason for remedial mechanical operations today is tubing failure due to erosion or corrosion. Some completion failures can be repaired by wireline or C/T methods but, in some circumstances, a full workover programme to pull the tubing is necessary. Typical failures are: • • • • • • • • •

Downhole safety valve mechanical failure or leak. Downhole safety valve leak. Casing, packer or tubing leak. Casing collapse. Tubing collapse. Cement failure. Gas lift failure or inefficiency. ESP or hydraulic pump failure. Recover fish unable to be recovered by other methods.

A full workover programme usually entails the placement of an overbalance kill fluid against the formation unless it can be isolated using a plug, e.g. a W/L plug in a permanent packer tailpipe or setting of a through tubing plug in the casing above the producing zone(s).


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3.5 STIMULATION OF LOW PRODUCTIVITY WELLS There are many reasons why a well may have low productivity, for instance: • • • • • • • • •

Formation damage. Low permeability. Pressure depletion. Liquid hold up in a gas well. Gas slip in an oil well. Excessive water or gas production; Refer to Section 3.3. Sand or other fill or debris; Refer to Section 3.2. Mechanical failure; Refer to Section 3.4. Artificial lift failure.

You will note that some of the above have already been addressed in previous sections. With regard to the others in the list, there may be a number of possible solutions for each problem. For instance: • Reservoir problems such as formation damage and low permeability can sometimes be improved by stimulation operations such as acidisation or hydraulic fracturing. • In oil or gas wells where there is liquid hold up or gas slip, this is often countered by installing smaller diameter tubing strings. These may be reeled tubing strings installed inside the original completion by large size C/T units.This tubing reaches down into the sump and provides a smaller flow area to improve liquid lift. These reeled strings are normally 23/8 ins., 27/8 ins. or 31/2 ins. OD and are run and hung off on a wireline lock or similar device. • The tubing is snubbed into the well by normal C/T methods from large reels. When the correct length of tubing is in the well and has been attached to the lock mandrel, it is run to setting depth and set on regular size C/T. • The main disadvantage with this solution is the high weight of such large reels which is often above the lifting capacity of some offshore installations. Smaller, more manageable, reel sizes entails more undesirable offshore connections to make up the full length of tubing required. These problems, however, are outweighed when set against the costs of a full programme to re-complete. • An artificial lift system is usually required in any low permeability well to give adequate production rates. A work programme to re-complete this type of well is required once the well flow has reached the minimum economic acceptable natural flow. If the well has already been on gas lift and it is no longer efficient, then the design should be reviewed to optimise the existing gas lift mandrel spacing against re-completing with the optimum mandrel depths.

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3.6 PARTIALLY DEPLETED RESERVOIRS Similar to low permeability wells, in a depleted oil reservoir, an effective artificial lift system can be installed to increase production. If a well was originally planned and designed for gas lift and completed with gas lift mandrels in the string then the gas lift valves are simply installed by wireline intervention. However, if a re-completion is needed, a full dead well workover would necessary. In high angle wells, gas lift valves can be installed with coiled tubing methods. Improved recovery by reservoir pressure maintenance is usually the best long term approach to increased production rates. 3.7 SAND CONTROL There are normally two solutions to control unconsolidated sand and these are; to gravel pack or; install a pre-packed screen although resins are occasionally used; See Section 1.2.1 d).The drawback of having to implement such sand control measures is that they reduce productivity typically by 10% to 15%. The installation of a gravel pack entails a full workover and re-completion although new snubbing methods with HWO unit have now been developed. For a successful gravel pack it is important to ensure that clean fluids (containing little or no dispersal solids) are used on initial completion or when the gravel pack is installed. A second requirement is that the gravel is correctly sized in relationship to the formation sand to prevent further ingress or alternatively cause a blind off. It also is desirable, if completing in a sand zone that is known to be unconsolidated, that the gravel pack is installed immediately. As it is more difficult to install at a later stage. If an open hole (external) gravel pack is required the hole will need to be enlarged to about twice its size by under-reaming first before the liner/screen is run. Properly sized gravel is placed outside the screen by reverse circulation techniques. External gravel packs are utilised when high production rates are required. Internal gravel packs are the norm but do carry a penalty in reducing production rates. The use of pre-packed screens has risen in recent years as they can often be installed in an existing completed well avoiding re-completion, however they are more prone to blinding off as they do not provide the same effectiveness as a regular gravel pack in controlling the production of fines.


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GENERAL

4.2

SNUBBING / HYDRAULIC WORKOVER UNITS (HWO)

4.3

COILED TUBING UNITS

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4. WELL INTERVENTION SERVICES 4.1 GENERAL Well interventions in the context of IWCF are servicing operations conducted through the Xmas tree (through-tree) on live wells. These are carried out by the following methods: • • •

Wireline (both electric line and slickline). Coiled tubing. Snubbing.

Well service operations or workovers on dead wells where the Xmas tree is replaced by well control equipment, are carried out by: • • •

Drilling rigs. Workover rigs. Hydraulic workover units.

During workovers, it is probable that well interventions with wireline and/or coiled tubing are required as part of the work programme to prepare the well for tree removal or establish production post workover. Many offshore installations have drilling rigs onboard used for the drilling phase of a development. These units are often retained to conduct well servicing operations on fields which frequently have wells requiring servicing although it is becoming more common for the drilling units to be demobilised and dead well servicing to be accomplished by a Hydraulic Workover Unit.Where a drilling rig is available for well servicing, it is obviously more economic for it to be used than mobilising an HWO unit. On installations which have not retained the drilling rig, or on small platforms (drilling performed with a jack-up rig), the HWO unit is commonly used. This is due to their easy deployment and their small footprint. On subsea wells, normally the only means of conducting a well intervention is to use a semisubmersible vessel (drilling unit, DSV or specialised well servicing unit) from which a workover riser can be deployed. However, if the work programme can be conducted solely with wireline, this can be successfully carried out by subsea wireline systems deployed from well servicing vessels (for example the Stenna Seawell). These vessels also have the capability to carry out subsea tree change outs once appropriate barriers have been installed by wireline. Well control equipment used on well interventions in live wells is specific to the particular service being used for the intervention, albeit BOPs and strippers all operate under the same principles.The main differences in the systems usually lie in the design of BOP ram elements, strippers or stuffing boxes, grease heads used in wireline braided line operations and the configuration of these above the Xmas tree.


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BOPs are usually compact for manipulation into position above the Xmas tree or onto a riser often used in platforms arrangements. They are fitted with flexible hoses to enable ease of installation and to reach between the BOP hydraulic control system and the BOPs when in situation. The connections on the BOP must be compatible with the riser/tree connection and lubricator or be supplied with appropriate crossovers. Well intervention pressure control procedures are addressed in Section 7. 4.2 SNUBBING/HYDRAULIC WORKOVER UNITS (HWO) The Snubbing/HWO Unit is a well service unit utilised for both snubbing and dead well servicing. Snubbing is the process of ‘tripping pipe in a well which has a surface pressure great enough to eject the pipe if no restraining force is applied’; this is termed the ‘pipe light’ mode. Stripping is the term for moving pipe through a rubber element to contain pressure whether it is in the snubbing mode or ‘pipe heavy’ mode (where the pipe is too heavy to be ejected). In practice, however, snubbing has come to mean all of the operations conducted in a live well. The HWO unit is also used in place of a conventional drilling or workover rig on dead well servicing as it is easily mobilised, has a small footprint and is cost effective in comparison to mobilising a workover rig. They are also very useful when working in confined spaces and with small diameter (skinny) pipe where a drilling rig’s instrumentation is generally not sensitive enough. An HWO unit would only be used before C/T on a snubbing job where: • • •

There is insufficient space above the wellhead or deck space. When rotational torque required on the pipe is greater than that available from downhole motors. Where pressures exceed the rating of C/T pipe i.e. circa 5,000 psi.

The first snubbing units were mechanical units using mechanical advantage in order to force the pipe in the hole against well pressure. In the development of the hydraulic type unit, the power to raise and lower the tubing was provided by a set of hydraulic rams through a set of bi-direction travelling slips or snubbers.The main elements of an HWO unit, See Figure 4.1, are as follows: • • • • • • • • •

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Hydraulic jack assembly. Guide tube. Splined tube (only on Halliburton/Otis units). Travelling slips. Stationery slips. Access window. Rotary swivel. Hanger Flange Power tongs.


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Work basket. Control panel. Hydraulic power pack. Hose package. BOP system. Strippers. Circulating system.

HWO units are supplied in a range of lifting capacities (lbs. in thousands), 60K, 90K, 120K, 200K, 250K, 400K and 600K. Snubbing capacity is half of this rating. When used instead of a conventional drilling or workover rig, the well would be killed and plugged, the Xmas tree removed and BOPs installed on the casing head. It can also be used for re-completing wells as it has the capability to run and pull completion strings by running the downhole safety valve control line through the access window. Hydraulic Jack Assembly As described earlier, the jack assembly consists of one or more hydraulic cylinders that travel in a vertical direction to move pipe in or out of the hole. For higher snubbing or lifting power, more cylinders are added into the system which reduces running speed unless larger capacity pumps are used. The operator controls the hydraulic power to the jack as the weight of pipe changes or as the weight of pipe overcomes well pressure and changes from snubbing to lifting and visa versa. Guide Tube This is simply a tube which prevents the bucking of the pipe under snubbing forces. It should be sized to be just larger than the particular tubing to be run or pulled to constrain lateral movement. It travels up and down with the hydraulic jack. Splined Tube Some units have a splined tube which passes rotational torque force generated by the rotary table through to the bottom plate and hence to the wellhead. If a splined tube is not used, the forces are transmitted through the hydraulic cylinders possibly reducing the operating life. Travelling Slips The travelling slips, or snubbers, are attached to the upper end of the jack and grip the pipe to push it into or pull it from the hole. There are two sets, one for snubbing and one for lifting. As a pipe is snubbed into the hole, it comes to a balance point which changes from pushing to holding back weight, the point the lifting slips take over.


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Stationary Slips The stationary slips hold the pipe while the travelling slips are released for the next stroke. Like the travelling slips, there are two sets, one for hold upward force and one for holding downward weight. In high well pressures, the second set can be used as back-up to the primary slips. These would be changed at or around the balance point. Access Window The access window (work window) is installed at the base of the jack between the stationary slips and the stripper and is the access for stripper rubber change out or for installing tools in the string. It must also help guide the pipe like the guide tube. Power Swivel The power swivel (or Rotary Head) is used for rotating the pipe for drilling or milling operations. It, like the other systems, are hydraulically powered and controlled from the control pane. Hanger Flange A hanger flange (also known as a tubing hanger assembly) is a pressure containing component sometimes used in the blowout preventer stack to hold pipe and toolstring in both the 'light' and 'heavy' directions. It is usually incorporated near the top of the BOP stack between the stripper bowl and the upper stripping ram or annular BOP. It is commonly used when changing the stripper rubber element or adding a tool joint which might be damaged if run through the slips.The hanger flange is also a useful aid in fishing operations with its ability to hold varying diameter toolstrings such as wireline tools. Vertical tooth type dogs can be used in the hanger flange to prevent pipe or tool rotation. Power Tongs Power tongs are used to make up and break out the pipe connections.They are located in the workbasket and controlled hydraulically from the control panel. Work Basket The workbasket is the work platform of a HWO unit and is located at the top of the hydraulic jack and on which the operator and assistant perform the manual functions including the picking up, laying down, stabbing, making up or breaking out of the pipe joints. Control Panel The control panel is mounted in the work basket and is usually in two sections, one for the operator’s use and one for his assistant. From here, all of the unit functions are controlled, generally shared between them with the exception of the BOP shear rams which are normally operated from the deck. 4-4


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Work Basket

Fluid Storage And

Gin Pole

Choke

Processing

System

Stationary Slips Hoses

Work Window Tool House

Fill Line

Stripper Bowl Hanger Flange

Mud Pump

Drain Line

Bleed

Tool Box

Equalise Line

Line Ground Based BOP

Control Units

Spares

Choke Line

Upper Kill Line

Power Unit Fuel

Figure 4.1 - Typical Snubbing/HWO Unit © ABERDEEN DRILLING SCHOOLS 2001

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Power Pack The power pack and it’s accessories consist of a diesel engine and hydraulic pumps. The output from the pumps is regulated to the various pressure ratings of the hydraulic functions. It displays the various function pressure on gauges. Hose Package The hose package transports the hydraulic fluid to and from the various functions, some of which are high up on the unit and are therefore of considerable length. Some of the hoses can experience very high pressures and must be thoroughly tested before use. BOP System The BOP configuration is dependent upon whether the HWO unit is being used as a rig on a well which has been killed, or in the snubbing mode rigged up above the Xmas tree. If on the former, the BOP configuration will be like that in a drilling situation and may be covered by the operator’s well control policies and procedures. If on a snubbing job, the configuration is quite different being rigged up above the Xmas tree. Refer to Section 7 for all well control equipment and procedures. Strippers The strippers control well pressure when snubbing or any time surface well pressure is encountered.There is a variety of stripper rubber materials for different pressure regimes and well fluids. These will vary in well life according to their resistance to the well fluids, gas or erosion due to roughness of the wall of the pipe being run, or pulled. Circulating System Pumps, chiksans, Kelly hose and a circulating swivel are the main components of the circulating system.The pumps are generally high pressure in order to cope with the maximum anticipated circulating and surface pressure. If nitrogen is to be used, the hose and chiksans should be suitably rated for such service. A safety valve or Kelly cock must always be installed between the Kelly and the swivel to allow safe changing of the hose or swivel, if necessary.

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4.2.1 Wireline Unit Wireline is the oldest and most common type of well servicing method. It is extremely efficient, economic and relatively easy to rig up and deploy. Electric line services provide essential information about the reservoir and the completion and performs many services, typically: Logging - depth determination, cement bonding, sonic, nuclear, temperature, pressure, spinner, caliper, density, dipmeter, profile and so on. • • • • •

Calipering. Downhole sampling. Perforating. Setting bridge plugs, packers and cement retainers. etc.

This is achieved by communicating with the tools through the conductor cable. Mechanical wireline also known as slickline (as the line has a smooth OD), is used to conduct mainly mechanical operations such as: • • • • • • • • • • •

Installing flow controls. Installing gas lift valves. Depth finding. Plugging. Bailing. Paraffin cutting. Tubing gauging. Setting bridge plugs. Fault finding. Fishing. Logging - through-tubing BHP gauges or the latest electronic solid state logging tools such as spinners, CCLs, etc.

The slickline unit can also be rigged up with braided line for heavy duty wireline operations such as running heavy, large tools or performing heavier duty fishing operations. A more recent development in wireline services is the Heavy Duty Wireline Unit used mainly for fishing jobs where regular fishing methods have failed. These units, in conjunction with heavy duty tooling, are so powerful they can destroy normal wireline tools and devices, if desired. Although wireline conducts most tasks required for well servicing, it is obviously limited in its abilities. It also has a role in dead well servicing as it is normally required for plugging the well to make it safe prior to Xmas tree removal and BOP installation. It is also used to conduct


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remedial operations such as setting bridge plugs, re-perforating etc. It’s greatest limitation, due to using gravity as it’s motive force, is in working in high angle or horizontal wells with inclination angles higher than 70˚. 4.2.2 Wireline Units As pointed out earlier, there are two types of wireline unit - the electric line or logging unit and the mechanical or slickline unit. Both types of unit are constructed similarly in that they have: • • • • •

Power pack. Operator’s/engineer’s cabin. Winch, including a wireline drum or reel. Spooling or measuring head. Weight indicator and pulleys.

Wireline units must be self contained and able to be mounted on a truck (or trailer) or portable to enable trucking and/or shipping to the well site. A typical wireline unit is shown in Figure 4.2. Power Pack The power pack is normally a diesel driven hydraulic unit and provides hydraulic power through supply and return hoses to the winch. Power packs are normally fireproofed and certified for division 1, zone 2 hazardous areas. Operator’s/Engineer’s Cabin The cabin is an integral part of the winch unit situated directly behind the drum for direct observation and monitoring of the wireline spooling. It contains the winch and possibly the power pack operating controls. In an electric line unit, it also contains all of the electronic instrumentation, computing and log printing equipment. Electric line units have fine smooth controls for accurate logging operations whereas the slickline unit has a wide range of speeds for both fine and very fast operation when jarring. Winch The winch consists of the wireline reel driven by a hydraulic motor controlled from the console in the cabin all of which is mounted in the unit frame. Hydraulic power is supplied from the power pack. The reel controls have a forward and reverse directional valve, a number of gear ratios to cover a wide range of speeds and a hydraulic bypass valve for fine control within each gear range. The reel is driven by chain drive from the gearbox and has a brake band. If there is two reels on the winch, slickline and braided, there is an additional manual operated clutch system for reel selection.

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Spooling Head The spooling or measuring head controls the winding of the wire off and onto the reel and also measures the length of wire spooled off the drum. The depth measurement is given on a odometer via a cable drive and a precisely machined measuring wheel (one for each size wire).The wire is held against the measuring wheel by pressure wheels to eliminate slippage. Electric line units usually have electronic type depth measurement devices.

Weight Indicator and Hay Pulley The weight indicator can be mounted on the hay pulley or be an integral part of the spooling head. If mounted at the hay pulley, the weight sensor is a load cell placed between the hay pulley and the tie down chain.The cell is connected to the indicator situated in the unit with a long hydraulic hose. The system is graduated for the wire to pass around the hay pulley at an included angle of 90˚ If this angle is not maintained, there will be an error in the readings. Correction tables are available which correct for varying angles. Modern units usually have more sophisticated type weight indicators, some hydraulic and others electronic. These units must be regularly serviced and checked for accuracy as this is fundamental to wireline service especially using relatively low strength wire. The hay pulley is the device used to turn the wire from the horizontal plane to the vertical up to the lubricator stuffing box sheave. As well as turning the wire it also moves the forces generated on the wire into the same axis as the lubricator reducing any possible bending moments. It has been known for a hay pulley failure due to severance of the tie down chain, causing the lubricator to break off the well.


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Figure 4.2 - Typical Wireline Rig Up

4.2.3 Types of Wirelines Electric line Cable used on electric line units can be either monoconductor, coaxial or multiconductor braided line and supplied for various service conditions. Each particular type has a range of sizes and specific uses according to the required service or tool being run. Careful handling of electric line is essential, especially with the smaller sizes and when rigging up, to prevent line damage and penetration of the core insulation leading to subsequent loss of signal. Slickline Slickline is a high strength monofilament steel line and is available in common sizes of 0.082 ins., 0.092 ins., 0.108 ins. and 0.125 ins.These are also supplied for various services conditions. Being slick the OD of the wire is easy to seal around using a simple packing device called a stuffing box where as the cable requires a grease seal arrangement. Braided Line Braided wireline used for heavier duty wireline operations is supplied in 3/16 ins. and 7/32 ins. sizes. 4-10


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4.2.4 Wireline Lubricators and Accessories The wireline lubricator when assembled acts like pressure vessel on top of the Xmas tree into which the wireline tools are ‘lubricated’. It consists of: • • • • • •

Wellhead adapter. Wireline BOPs or wireline valve. Lower lubricator section(s). Upper lubricator section(s). Stuffing box or grease head. Line wiper.

It is extremely important that a wireline lubricator pressure rating meets the maximum anticipated surface well pressure. Lubricators must be designed, not only to withstand the stress caused by internal pressure but also from stresses caused by jar action or high pulling forces. To install the tools, the lubricator must first be isolated from well pressure at the Xmas tree, usually the swab valve, and all pressure bled off through the bleed-off valve. The lubricator is then broken out at the connection immediately above the BOPs and the tools, after attaching to the toolstring, are pulled up into the lubricator bore and the lubricator re-installed. The lubricator should then be pressure tested before opening the tree and running in the hole. Wellhead Adapter This is basically a crossover to mate the BOP to the tree cap and is usually a quick type connection named a ‘quick union’. In some cases the adapter may be from a quick union to a tree flange. Wireline BOPs Wireline BOPs (sometimes referred to as wireline valve) are installed immediately above the wellhead adapter or on top of a wellhead riser. In some situations for ease of operation and safety, a BOP may be placed both above the tree and on top of a riser. On slickline operations in low pressure wells, a single BOP is installed dressed with slickline rams to close and seal around the wire. On high pressure wells a dual BOP is used, the lower rams dressed for slickline and the uppers with blind. The injection point is used to pump grease if there is leakage past the rams. When running cable, a dual BOP is used with both rams dressed for the particular cable size and a grease injection point also available between the rams. In a situation where slickline and braided line are both being used, a triple BOP would be installed with the lower and middle rams dressed for the braided line and the upper for slickline. On electric line jobs, triple BOPs are used, the upper rams being blind. © ABERDEEN DRILLING SCHOOLS 2001

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Lower Lubricator Sections These are sections of thick wall tube usually between 8 to 10 ft. long with quick union connections at each end and made up in a total length to accommodate the longest tool to be run.They are installed immediately above the BOPs and usually have the same bore size as the Xmas tree.The section above the BOPs must have two bleed-off valves (contingency for one being plugged by debris or hydrates). Riser sections, used in offshore platforms to reach from the wellhead deck to another working deck, are similar to lubricator sections except they are generally much longer in length and may be installed between the wellhead adapter and the BOPs. They may also be of even thicker section to support the increased weight being carried. Upper Lubricator Sections These accommodate the toolstring which has a smaller OD than the toolstrings which are normally 1 ins., 11/2 ins. and 2 ins., although larger sizes are available for heavy duty work. The section connecting to the lower lubricator will have a connection to mate with that of the lower lubricator sections (or visa versa). Stuffing Box or Grease Head The stuffing box or grease head terminates the top of the lubricator. The stuffing box contains packing which is squeezed to seal around the line. The packing is squeezed by an adjustable packing nut which is hand adjusted although most stuffing boxes are now being supplied by remote hydraulic actuated packing nuts so that they can be adjusted from the deck eliminating the need for personnel to be lifted up to the top of the lubricator and, hence, is safer. The stuffing box also incorporates a sheave which turns the wire through 180˚, from the outside of the lubricator into the bore. The grease head is used on braided line, electric line or plain cable. It seals around cable by grease being pumped, at higher pressure than that inside the lubricator, into the small annulus space between a set of flow tubes and the cable filling the cable interstices. The grease, being at higher pressure, tends to flow downwards into the lubricator and also upwards out of the tubes. The upward flow is forced out through a return line for disposal by activating a cable pack off above the tubes. Downward flow is only constrained by the differential pressure applied between the grease and the lubricator pressure. Adjustments must be made to maintain the optimum conditions between grease lost to the hole, amount of gas entrained in the grease returns and differential pressure. Line Wiper This is a tool which attaches to the hay pulley when the wire is being pulled to remove all contaminants from the wire before it is spooled. 4-12


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4.3 COILED TUBING UNITS Well servicing using coiled tubing (C/T) has grown significantly with the development of tooling and tubing technology. In recent years the size of tubing available has increased from the original 1 ins. through 11/4 ins., 11/2 ins., 13/4 ins. and now 2 ins. Even larger sizes are now being used as siphon strings etc. but these are not yet generally used as workstrings. Along with this increase in size of tubing has come material improvements to give higher performance. C/T units have largely replaced snubbing units for operations on completed wells and their versatility, due to new tooling developed, has extended their range of capabilities in recent years. The range of services now provided includes: • • • • • • • • • • • • •

Drilling and milling using hydraulic motors. Casing cutting. Circulating. Tubing clean outs (sand or fill). Cementing. Through-tubing operations. Tubing descaling. Running, setting, pulling wireline pressure operated type tools. Fishing wireline tools. Logging (stiff wireline). Nitrogen lifting. Selective zonal acidising. Perforating.

Much of the recent increase in capability is due to the increased performance of downhole motors which provided the ability to rotate enabling drilling and milling operations etc. The limitation of C/T is usually the pressure rating of circa 5,000 psi. and the depth to which it can be run, constrained by it’s relative low strength. It is also limited in it’s service life due to the bending cycles over the reel, and to a lesser extent the goose neck, in conjunction with the service conditions it encounters. These bending cycles force the tubing to exceed it’s elastic limit inducing fatigue, and, therefore, reducing the working life before failure.Tubing under pressure while passing over the reel and goose neck, dramatically decreases this cycle time to failure. Most C/T service companies have developed computer programmes, using logging databases, to determine the time to failure for each tubing size and type of material to which a factor of safety is applied.This is an inexact science but, due to the safety factor, there is actually very few recorded well site incidents due precisely to tubing failure. More than likely, service life is much shorter than actual life.


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All C/T units, See Figure 4.3, are constructed similarly and consist of: • • • • • • •

Operator’s control cabin. Tubing reel. Power pack. Goose neck. Injector head. Stripper. BOP system.

Operators Control Cabin The cabin houses all of the controls for the reel and the injector head, and also all electronic logging systems and instrumentation. The controls operate the hydraulic valves and pressure supplied from the power pack. It is placed directly behind the reel to provide the operator with a full view of all activities especially the spooling of the tubing off and on the reel. Tubing Reel The reel stores the tubing which is coiled around the core of the reel. Ideally the core should be as large a diameter as possible to prevent severe bending of the tubing but must be of a manageable size for transporting to and from well sites. The radius of the core of the reel is sharper than that of the goose neck e.g. 24 ins. (4 ft. dia.) versus 72 ins. for 11/4 ins. tubing, hence most tubing fatigue is caused at the reel. The reel is driven by chain from a hydraulic motor controlled from the control cabin. The tubing is pulled off the reel up over the gooseneck by the injector. The reel holds constant back tension to prevent the spool unravelling and to keep the tubing steady. 4.3.1 Power pack The power pack is the provider of all hydraulic power. It consists of a skid mounted diesel engine and hydraulic pumps and supplies regulated pressure for all the systems in the reel, injector head, BOPs and the control cabin. Goose Neck The gooseneck is simply a guide which accepts the tubing coming from the reel and leads it into the injector chains in the vertical plane. The goose neck guides the pipe using sets of rollers in a frame spaced on the recommended radius for the tubing being run i.e. 72 ins. with 11/4 ins. tubing etc. Injector The injector is the motive device which imparts upward or downward movement to the tubing and is mounted above the BOPs on the wellhead. It must be supported as the connection to the BOPs is not designed to absorb the weight and lateral forces caused by the tension in 4-14


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Figure 4.3 - Typical Coiled Tubing Unit


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the tubing from the reel.This support can be a crane for land wells (providing the lifting gear and pad eyes are rated for the weight of equipment and forces encountered) or to a mast or derrick offshore. Free standing frames with hydraulic jacking legs are also available where no other means of rigging up is available. Movement is imparted to the tubing by sets of travelling chains equipped with gripper blocks which are hydraulically driven.The gripper blocks grip by friction which is adjustable through a hydraulic piston applying pressure across the chains. This pressure must be sufficiently high enough to grip the tubing eliminating slippage but not excessively high enough to crimp the tubing. Stripper The stripper is situated below the injector head in the injector head frame. It is designed to be as close as possible to the gripper chains to prevent buckling due to snubbing forces. The stripper is hydraulically controlled to press the rubber element against the tubing to create a seal. The stripper rubber is exposed to wear from the roughness of the pipe OD and will need to be changed from time to time which can be done on the wellhead by closing the BOPs and removing well pressure. BOP System The BOPs are very similar in function to wireline BOPs and are mounted above a wellhead adapter. They usually have four sets of rams dressed as follows, top to bottom: • • • •

Blind. Shear. Slip. Pipe.

The shear rams usually have the ability to cut stiff wireline i.e. C/T with electric line cable inside it, used on C/T logging operations. In some areas of the world, an additional Shear/Seal valve is installed between the BOPs and the wellhead adapter as a tertiary barrier.The shear seal valve has the ability to cut the tubing and effect a seal. It is generally tied into a higher volume hydraulic pressure supply than available from the C/T unit such as a rig Koomey or independent system etc. 4.3.2 Tubing There are a number of coiled tubing manufacturers but they are mainly US or Japanese companies. Some of the US companies use Japanese supplied steel for tubing manufacture. The normal method of tubing manufacture is to produce rolled plate steel which is cut into long flat strips. Each strip is then progressively folded round with rollers and formed into a 4-16


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long spiral. When it is completely formed into a round tube, the edges, now abutting, are welded.These individual lengths are then welded together to produce the length required to be contained on a shipping reel. Continuously milled tubing has now been introduced but is much more costly. The common steel used is an American alloy grade A606 type 4 modified, suitably quenched and tempered, which provides the best economic combination of ductility and strength to combat the cyclic bending stresses. By specially selecting billets from the furnace to meet particularly tight tolerances of chemistry, higher grades can be produced such as QT-800. More exotic pipe materials are also being manufactured but have corresponding cost penalties. 4.3.3 C/T Unit Accessories In conjunction with the C/T unit, many of the services require additional auxiliary equipment such as pumping or nitrogen services.These may require cryogenic converter pumps, tankage, hoppers, filtration units and interconnecting piping. These are connected up to the tubing reel inlet swivel which allows the reel to rotate while still pumping. Any hazardous materials must be handled appropriately by ensuring that they are located in a safe area and all necessary safety handling precautions taken. For instance when using nitrogen, the deck below the equipment should be covered with wood and trays to contain and protect the deck from damage due to spillage, and water available to wash down the deck if nitrogen does breach the barriers. C/T Tooling Tooling can be categorised into standard toolstrings and specialist tools. These toolstrings contain the standard tools used in all applications to which the specialist tools are attached. The complete assembly is referred to as the Bottom Hole Assembly (BHA). A typical toolstring contains: • • •

Tubing connector. Dual flapper valves. Emergency release sub.

Optional standard tooling: • • •

Circulating subs. Swivels. Bull noses.

Specialist tooling: • • •

Downhole motors. Jetting nozzles. Wireline type hydraulic operated tools.


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• • • • •

Through tubing packers. Bridge plugs. Perforating guns. Logging tools. etc.

The dual flapper valves are an integral element in well control as they contain well pressure from the inside of the tubing.The dual flappers give double isolation and meets most legislative requirements. Therefore, when the BOP tubing rams are closed well pressure is contained to both below the rams and from the tubing, hence the well is safe for corrective actions. A split in the tubing below the BOPs circumvents the dual flappers seals and, in this situation, the shear rams would be closed to contain well pressure.

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5.1

FORMATION DAMAGE

5.2

DAMAGE PREVENTION

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5. PREVENTION OF FORMATION DAMAGE Damage to the formation can be caused by many mechanisms. Although some of these may be due to well conditions, the majority are through contamination of the formation by foreign substances not only during the drilling, completing and producing phases but also during the servicing of a well. These damage mechanisms are described in Section 5.1 below. To prevent damage which reduces the productivity of a well, it is essential to be able to prevent or reduce formation damage by preferably isolating the formation from the contaminants or, if not possible, reducing the amount of contaminants in the fluids or conducting remedial stimulation operations. These are discussed in Section 5.2. 5.1 FORMATION DAMAGE The types of damage which can occur during the different phases of a well’s life are described in the following section. See Figure 5.1 for the effects of skin damage to the well pressure profile.

Figure 5.1 - Formation Damage Pressure Drop

© Aberdeen Drilling Schools 2001

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IWCF WELL INTERVENTION PRESSURE CONTROL PREVENTION OF FORMATION DAMAGE

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5.1.1 Drilling/Casing Drilling fluids usually contain chemicals and/or solids as bridging agents to control the loss of drilling fluids. Fluid losses can lead to well control problems and are also expensive to replenish especially when using the more exotic mud systems such as Pseudo or Oil based muds etc. Drilling fluids cause the following types of damage: • • •

Solids plugging of pores, vugs or fractures both natural or induced. Clay swelling reducing permeability. Filtrate penetration detrimentally changing the relative permeability to producing fluids.

Similar damage can be caused during the casing cementing process for the production casing by cement pre-flushes and cement slurries. Non-damaging drilling fluids are often used to penetrate the producing formations when the wells are to be completed with open hole, barefoot or gravel pack type completions. In the main, however, damage done during the drilling is not a serious problem in most wells as they are usually to be perforated. The perforating depths, under normal circumstances, exceed the depth of any damage areas. They also generally have a total flow area greater than the tubing area, hence there is little impediment to achieving maximum production rates. Perforating is usually carried out in a clear non-damaging fluid such as brine or fresh water so that minimal post perforating damage is caused. When damage exceeds the perforating depth or occurs in an open hole type completion, this may be reduced by acidising or fracturing. 5.1.2 Completing The damage caused during the completing phase, compared to drilling, is generally minimal if good completion designs and practices are employed. Most damage caused would be through contamination by fluids or pills used containing loss control materials (LCM) and other foreign bodies. Possible damage may be: • • • • • •

Plugging of pores, vugs and fractures by LCM. Clay swelling due to incompatible well fluids. Deposition of mill scale, rust or thread dope. Perforating tunnels plugged by perforating debris from the shaped charges. Perforating tunnel compaction or crushing caused during the perforating process. Cleaning up at too high a rate causing movement of formation fines to plug pores.

With current technology it is easy to complete wells and displace to clean filtered brines or fresh water before perforating, thereby reducing the risks of any damage occurring. Also, most perforating is done with an underbalance pressure in the tubing which reduces the amount of invasion. This underbalance is created by displacing the tubing (fully or partially) to a lighter 5-2


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gravity fluid such as diesel, base oil or fresh water. If a fluid cannot provide sufficient underbalance or if a very high underbalance is demanded, nitrogen can be used although is much more costly. All completion and service equipment, especially the tubing should be thoroughly cleaned before being installed and thread dope used sparingly. If the well is to have an open hole type completion, then the well fluids programme should be designed to prevent formation damage. However, in practice this is difficult and most engineers acknowledge damage will be caused to some extent. In the situation where LCMs need to be used to support the workover fluid, the engineer must select a material which can be easily removed afterwards. Sized salt or calcium carbonate are examples where the former is cleared by flushing with water and the later with an acid wash. 5.1.3 Producing Although it maybe of some surprise, damage can occur during the producing phase of a well. This is normally due to the production of asphalt, wax or scales but can also be due to other chemicals contacting the formation. Common types of damage: • • • • • • •

Reduced permeability if formation is in contact with corrosion, scale or paraffin inhibitors. Formation or perforation blocking with precipitated scale. Asphalt deposition around the wellbore can cause plugging and oil wetting which in turn can cause emulsion blocking. Permeability reduction due to movement of fines through the reservoir. Altering relative permeability detrimental to production due to increasing water production. Clay swelling due to contamination with incompatible brines or water. Plugging due to contamination with fill, silt or crud.

Many of these can be remedied or reduced by clean-out or stimulation operations.


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5.1.4 Well Intervention Damage will be caused by some well interventions and most notably when fluids are placed against the formation. Typical damage is: • • • • • • • •

Pore, vug or fracture plugging by solids in circulating or well kill fluids. Permeability reduction through filtrate invasion by circulating or kill fluids. Sand face/cement breakdown due to effects during acid stimulation. Permeability reduction due to insoluble precipitates formed during acid stimulation with hydrofluoric acid. Formation blocking with long string molecules in high viscous fluids or diverting agents. Clay swelling from incompatible brine or water contamination. Pore plugging due to using non-damaging fluids. Pore or perforation plugging due to bullheading with scale or debris in the tubing and casing.

To prevent the risk of any of these occurring, it is obviously that well interventions require thorough planning to minimise formation damage. 5.2 DAMAGE PREVENTION It should be an aim in any programme to prevent any damaging fluid from contacting the formation, if possible. If this cannot be achieved, then the use of clear non-damaging filtered brines should be adopted. In some cases where it is necessary to use LCM or similar materials then a post servicing stimulation should be considered to reduce the damage. 5.2.1 Well Plugging The best means of preventing formation damage is to isolate the fluids entirely from the formation by installing a barrier in the form of a mechanical plug but this is only possible if the well programme does not require work below the lowest plugging point.The most common method of installing a barrier is by setting a plug in a packer tailpipe nipple on wireline leaving well fluid or gas across the formation. The plug can then be inflow tested to confirm there is no leak. If the tubing is to be removed from the well, wireline plugs can only be installed in completions with permanent or permanent retrievable style packers.An alternative when working on monobore type completions, is to install a retrievable through-tubing bridge plug close to the top of the formation.This has an advantage in that the packer or liner hanger packer above can be removed without disturbance of the barrier. Whatever type of device is used for plugging, it must be designed so that it can be recovered from the well after the work is completed.The plug will likely be covered by some scale, rust and other debris and although most of it can be removed by washing or bailing, some will remain. Most devices used generally have a long mandrel with a fishneck which stands above the plug enabling washing and latching with a pulling tool. Other devices such as pumpthrough plugs, allow the plug to be opened by application of tubing pressure above it where 5-4


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after the well can be opened up to clean out the fill first before recovering the plug. Once the tubing is successfully plugged and plug tested, the well can be circulated to the workover fluid, i.e. brine, etc. 5.2.2 Workover Fluids Fluids used in completing or servicing operations have many applications.They are employed in perforating, cementing, fracturing, acidising, well killing, re-completing, milling, drilling, cleaning out and preventing fluid losses.They may also have an important long term function as an annulus packer or completion fluid. To provide the properties required for each of the above, many types of fluids are utilised, e.g. drilling muds, milling fluids, brines (including seawater), salt saturated brines, diesel and dead oil. Some like the drilling or milling fluids, must have cuttings carrying capability, cool the bit or mill and reduce friction to deliver hydraulic energy downhole. Others used, say for circulating purposes or to provide an overbalance only, may be clear brines or seawater etc. Completion or packer fluids are usually solids free to prevent drop out and sticking but are also dosed with biocide, corrosion and/or scale inhibitors for long term protection of the formation and tubulars exposed to the fluid. However, one important function of them all, whether used as a completion fluid or in a re-completion, is that they must provide an overbalance at the packer depth in case of a leak to control well pressure. Generally, the most economic fluid which meets all of the criteria is used and, if possible, it should be solids free and non-damaging. This criteria would tend to result in clear brines being used as they are cheap, readily obtainable, easily transportable and easily filtered in normal weight ranges. However the points which makes them desirable are also their worst features in that they have no bridging capability and are easily lost into the formation (unless the well is plugged). In this case, an LCM pill is usually placed against the formation to prevent or reduce the losses. The solids in the LCM pill are often designed to be removed by post re-completion flushing or acidising.The use of a high viscous pill as an LCM is not recommended as the long chain molecules which plugs the pores cannot be removed by these methods. 5.2.3 Clear Fluids At one time it was felt that poor well performance was due to other reasons other than by damage from drilling muds and other fluids. When it was recognised that some formations were sensitive to invasion by foreign fluids and particles that operators began to look closely at this subject, observing that fresh water was the biggest culprit. After this revelation, the use of low water loss muds, cements and non-aqueous fluids became the norm. Clear brines have become the commonest workover fluids as they not only meet most of the criteria but are also a good medium in which to run and install tools and equipment.They are weighted by salts to achieve the desired densities. Brines are available in weights ranges from 8.3 to 21.0 lbs./gal.The heavier brines can be very corrosive to metals and hazardous to personnel, hence require special handling. Personnel © Aberdeen Drilling Schools 2001

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must use appropriate safety workwear and be aware of the hazards. They are also more difficult to prepare to prevent crystallisation or freezing. Composition of Brines The following list shows the various types of brines, composition and weight ranges: Potassium Chloride Sodium Chloride Calcium Chloride Calcium Chloride /Calcium Bromide Calcium Chloride /Calcium Bromide /Zinc Bromide Calcium Bromide /Zinc Bromide Zinc Bromide

KCl NaCl CaCl2 CaCl2/ CaBr2

8.3 - 9.7 lbs./gal. 8.3 - 10.0 lbs./gal. 8.3 - 11.8 lbs./gal. 11.8 - 15.2 lbs./gal.

CaCl2/ CaBr2/ ZnBr2

14.5 - 19.2 lbs./gal.

CaBr2/ ZnBr2

14.5 - 19.2 lbs./gal.

ZnBr2

13.5 - 21.0 lbs./gal.

Brine Selection Selection of the brine is not simply by picking the brine best fitting the particular weight range required or by cost. For instance, the weight range of sodium chloride may provide the hydrostatic pressure required in a well (say 9 ppg) but it causes shales and clays to swell reducing permeability. Therefore if clays were present, as observed from cores etc., the brine selected should be potassium or calcium chloride. Potassium chloride is corrosive and an inhibitor should be added to maintain a pH of 7 to 10. Fluid compatibility is essential in the fluids design. Preparation of Brines Brines are normally supplied in stored liquid form at the higher end of the weight range available and is transported in bulk to the well site.The density is normally adjusted by adding water. In some rare circumstances where a higher weight was desired or if the liquid had been accidentally contaminated with water, salt supplied in sacks would be added to build to the correct weight. Field mixing is not recommended as the handling systems usually are not able to meet the high standard of cleanliness required to prevent contamination of the brine from incompatible liquids or solids. When brine densities reach saturation point, the salt will either crystallise or settle out and pose a real hazard to operations.Temperature changes in the well can also cause crystallisation

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or solids fall out. Crystallisation is sometimes called freezing as it appears to form like ice. Filtration and Cleanliness Brines are usually filtered to a predetermined level of cleanliness, selected to meet the demands, by a filtration unit or a centrifuge. There are two main types of filtration units used are a DE Filtration Unit and a Cartridge Unit. The former uses Diatomaceous Earth formed as a cake on the faces of plates pressed together through which the fluid is pumped. Health and Safety The health of personnel and protection of the environment is paramount. The lower density brines such as sodium chloride are not harmful but the higher density brines are exceedingly toxic. These should be handled carefully and all personnel involved in mixing, storage and handling should wear protective clothing and goggles. An emergency dousing shower should also be easily accessible close to the workplace. Some brines are also very corrosive to workwear such as leather boots and all precautions should be taken to avoid contact or to ensure they are thoroughly washed after contact. Pollution Control In most countries, there is legislation regarding the use of hazardous materials, therefore, disposal should be in accordance to the local laws and the well site appropriately constructed to capture and retain leakage or spillage. All movement or spillage of these materials should be recorded and the appropriate authorities notified.


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6.

PRESSURE BASICS

6.1

FUNDAMENTALS OF FLUIDS AND PRESSURE

6.2

FORMATION PRESSURE

6.3

FORMATION FRACTURE PRESSURE

6.4

FORMATION INTEGRITY TESTS

6.5

MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP

6.6

CIRCULATING PRESSURE LOSSES

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6. PRESSURE BASICS 6.1 FUNDAMENTALS OF FLUIDS AND PRESSURE Understanding pressures and pressure relationships is important in understanding well control. Pressure is defined as the force per unit area exerted by a fluid i.e.: Pressure

=

Force –––– Area

Therefore, the formula can be changed to calculate the force from a given pressure and a unit area: Force

=

Pressure x Area

In the oilfield, pressure is usually expressed as the pounds of force that is applied against a one square inch area, i.e. pounds per square inch (psi.).Therefore, when a gas is placed in a pressure tight container, it exerts a pressure on all sides of the container. If the gas pressure is 100 psi., it exerts a force of 100 pounds (lbs.) on each square inch of the container area. Similarly, if a liquid is placed in a can, it exerts a pressure on the sides and bottom of the container due to the weight of the liquid which is also expressed as psi. In well control, both of these effects are of the utmost importance. Pressure can be expressed as absolute or as gauge pressure.Absolute pressure includes atmospheric pressure which is also applied due to the weight of the atmosphere and is 14.7 psi. Some gauges, especially BHP gauges, are calibrated in absolute terms, but regular gauges showing psig. indicate they have been calibrated at atmospheric pressure and the 14.7 psi. is excluded. Although this is a relatively small amount and can be ignored in most instances, it is important when gathering data for reservoir analysis. 6.1.1 Fluid Pressure A fluid is any substance that is not solid and can flow. Liquids, like water and oil are fluids. Gas is also a fluid. Under certain conditions, salt, steel and rock can become fluid and in fact almost any solid can become fluid under extreme pressure and temperature. In well control, fluids such as gas, oil, water and completion fluids, brines and mud are encountered. Fluids exert pressure which is caused by the density, or weight of the fluid. This is normally expressed in pounds per gallon (ppg) or pounds per cubic foot ( lbs./ft.3 ). Other abbreviations for these are lbs/gal and ppf 3 . As the pressure developed by a fluid is relative to the true vertical depth, it is often expressed as psi. per foot (psi./ft.). This is termed the fluid’s pressure gradient. The pressure gradient for a fluid is relative to the fluid’s weight or density.The higher the density, the higher the pressure gradient. To understand this relationship, it is helpful to visualise a cubic foot of fluid; See Figure 6.1.


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Figure 6.1 - Fluid Pressure Diagram

A cubic foot contains 7.48 US gallons. Therefore, a fluid weighing 1 ppg would weigh 7.48 lbs. The pressure exerted on the base (area) is: 7.48 lbs. ––––––– 1 ft.2

= 7.48 lbs./ft.2

1 ft.2 = 12 ins. x 12 ins. area = 144 ins.2, therefore the pressure per ins.2 is 7.48 lbs. ––––––– 144 ins.2

= 0.052 psi.

This relationship between a fluid weight in ppg and gradient pressure in psi./ft. is always the same, therefore 0.052 is a constant. Example: The pressure gradient of a 10 ppg fluid = 10 ppg x 0.052 = 0.52 psi./ft. Example: The weight of a fluid (fresh water) which has a gradient of 0.433 psi./ft. 0.433 psi./ft –––––––––– 0.052

= 8.33 ppg.

This constant is probably the most useful constant used in calculations. 6-2


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6.1.2 Specific Gravity Many fluids in the oilfield are also expressed in specific gravity (SG) as well as weight in ppg. It is also necessary to be able to convert SG to pressure gradient in order to calculate hydrostatic pressures. SG is the ratio of the weight of a fluid (liquid) to the weight of fresh water. Fresh water weighs 8.33 ppg and salt water is nominally valued at 10 ppg. Therefore, the SG of salt water is: SG of Salt Water

=

10ppg ––––– 8.3ppg

=

1.2

The SG of fresh water is 1.0. As the gradient of fresh water is known to be 0.433 psi./ft., to obtain the gradient of a fluid, it is simply necessary to multiply its SG by 0.433 psi./ft. Example: What is the hydrostatic pressure (HP) exerted by a true vertical 5,000 ft. column of brine with an SG of 1.17? HP of brine

=

1.17 x 0.433 psi./ft. x 5,000 ft.

=

2,533 psi.

6.1.3 API Gravity API gravity is another value used to express relative weight of fluids and was introduced by the American Petroleum Institute to standardise the weight of oilfield fluids at a base temperature of 60˚ F. Water in this case was also used as the standard and assigned the value of 10 API gravity. To convert from specific gravity to API gravity, the following formula is used. SG

=

141.5 –––––––––– 131.5 + API

Example: What is the SG of 30˚ API oil? SG

=

141.5 ––––––––– 131.5 + 30˚


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6.1.4 Hydrostatic Pressure Hydrostatic pressure (HP) is the pressure developed by a fluid at a given true vertical depth in a well.‘Hydro’ means water, or fluids which exert pressure like water and ‘static’ means motionless. So hydrostatic pressure is the pressure created by a stationary column of fluid.The hydrostatic pressure of any fluid can be calculated at any true vertical depth (TVD) provided the pressure gradient of the fluid is known. The previous calculations have dealt with fluid pressure with a gradient of one foot depth but it is now simple to determine the pressure exerted by a fluid at any true vertical depth by multiplying that pressure gradient by the true vertical height of the column in feet. The true vertical height of the column is the important factor in the equation, as it’s volume or shape is irrelevant. The equation is: where:

HP

= PG x TVD

HP = PG = TVD =

Hydrostatic pressure, psi. Pressure gradient, psi./ft. True Vertical Depth, ft.

Figure 6.2 - Measured Depth verses True Vertical Depth

Example: A 500 ft. TVD column of fresh water, what is the hydrostatic pressure ? HP

= 0.433 psi./ft. x 500 ft. = 216.5 psi.

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Example: What is the hydrostatic pressure of a 6,750 ft. well, filled with a 0.478 psi./ft. pressure gradient fluid which has a TVD of 6,130 ft. ? HP

= 0.478 psi./ft. x 6,130 ft. = 2,930 psi.

Example: A 12,764 ft. TVD well is filled with a 15 ppg fluid, what is the BHP? HP

= 15 ppg x 0.052 x 12,764 ft. = 9,956 psi.

Equipped with this knowledge, it is now easy to calculate the hydrostatic pressure with two of more fluids in a well provided the depths (TVD) of the fluid interfaces are known. Using the same formula, the HP for each fluid section is calculated in the same way and the sum of the individual calculations gives the HP at the bottom hole or well. Example: A 10,500 ft.TVD well has two fluids in the well, a 15 ppg fluid from TD to 7,125 ft. and 8.33 ppg fluid to surface, what is the HP at the bottom of the well ? HP of 15 ppg fluid

= 15 ppg x 0.052 x (10,500 - 7,125) ft. = 15 ppg x 0.052 x 3,375 ft. = 2,633 psi.

HP of 8.33 ppg fluid

= 8.33 ppg x 0.052 x 7,125 ft. = 3,086 psi.

Total HP

= 2,613 psi. + 3,086 psi. = 5,719 psi.


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6.1.5 Gas Correction Factors Most well servicing operations entails working with live wells whether using a throughtubing method or rig intervention. Even with a rig operation, the well must be prepared by being killed prior to the intervention. This involves dealing with gas in the well. Production wells with gas in the fluids will exert a static surface pressure equal to the formation pressure less the hydrostatic pressure in the production bore.The gas entrained in the productions fluids will segregate from the liquids as shown in Figure 6.3. In a static situation, the closed in tubing head pressure (CITHP) and hydrostatic pressure will balance the formation pressure. As discussed earlier, gas is also a fluid and exerts a hydrostatic pressure. Being compressible pressure affects the density of the gas. A set of correction factors are used which are used to calculate hydrostatic pressures at varying TVDs with a range of gas gravities, refer to Table 6.1. The correction factor, according to the TVD of the gas column and the gas gravity, is multiplied by the CITHP: HP Total Gas Pressure

= (Correction factor-1) x CITHP

or

= Correction Factor x CITHP i.e. surface pressure + gas hydrostatic

Example: What is the HP of a 5,000 ft.TVD column of 0.7 SG gas with a closed in tubing head pressure of 1,650 psi? HP of gas

= (1.129-1) x 1,650 psi. =

212.85psi.

Using the calculations already given in earlier sections and the gas correction factors, hydrostatic pressures in relatively complicated systems can now be determined. Example: What is the differential pressure between the annulus and tubing at a circulation device installed at a depth of 8,200 ft. TVD in the tubing string ? • • • • •

The following are the well conditions: The tubing/casing annulus is filled with a 10.29 ppg brine. The well is shut in at surface with a CITHP of 600 psi. There is a gas cap of 0.6 SG gas from 4,000 ft. There is 32 API oil from 4,000 ft. to 12,000 ft.

To help in the calculation, it is sometimes better to make a sketch; See Figure 6.3.

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CITHP

0.6 SG Gas

Annulus Fluid 77 lbs/cu ft

Gas/Oil Interface @ 4000 ft

32 API Oil

Circulating Point @ 8,200 ft Packer

Figure 6.3 - Example of Production Well © Aberdeen Drilling Schools 2001

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Well Depth 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 14,000 14,500 15,000

Correction Factors 0.6 Gravity 1.064 1.075 1.087 1.098 1.110 1.121 1.133 1.145 1.157 1.169 1.181 1.193 1.206 1.218 1.232 1.244 1.257 1.270 1.282 1.297 1.311 1.324 1.338 1.352 1.366

0.7 Gravity 1.075 1.089 1.102 1.115 1.129 1.143 1.157 1.171 1.185 1.204 1.214 1.239 1.244 1.259 1.275 1.289 1.306 1.322 1.338 1.354 1.371 1.388 1.405 1.422 1.438

0.8 Gravity 1.087 1.102 1.117 1.133 1.149 1.165 1.181 1.197 1.214 1.232 1.248 1.266 1.282 1.302 1.320 1.338 1.357 1.376 1.395 1.415 1.434 1.455 1.475 1.495 1.515

0.9 Gravity 1.098 1.115 1.133 1.151 1.169 1.187 1.206 1.224 1.244 1.264 1.282 1.304 1.324 1.345 1.366 1.388 1.410 1.433 1.455 1.477 1.500 1.523 1.548 1.573 1.596

Table 6.1 - Gas Correction Factors

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HP of brine in annulus at circulation device: = 10.29 ppg x 0.052 x 8,200 ft. = 4,387 psi. HP of gas cap:

= (1.087 (from table)-1) x 600 psi. = 52 psi.

HP of oil column Oil SG

141.5 = –––––––– 131.5 + 32 = 0.865

HP of oil column

= 0.865 SG x 0.433 psi./ft. x (8,200 - 4,000) ft. = 1,575 psi.

Total HP in tubing = HP of gas + HP of oil = 52 psi. + 1,575 psi. = 1,627 psi. BHP in tubing

= surface + HP of gas + HP of oil = 600 + 1,627 = 2227 psi

Differential pressure across circulation device = HP of annulus - HP of tubing = 4,387 psi. - 2,227 psi. = 2,160 psi. If the circulation device were to be opened, then the opening toolstring would be exposed to 2,160 psi. differential pressure. If using wireline, this pressure differential would need to be equalised before opening the device.


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6.2 FORMATION PRESSURE Some rocks contain fluids like water, oil and gas which are contained in tiny openings or pores. In a rock with pores, the measurement of the ratio of the pore volume to volume of the rock material is termed ‘porosity’. The linkage between pores is the flowpath for any fluids and is extremely important, e.g. a rock with many large pores which are not interconnected will not have any flow potential to the hole drilled into the formation, i.e. the fluids would be locked in place.The interconnection of pores make the rock permeable and the measurement of this factor is termed ‘permeability’. Formation pressure is the pressure of the fluids contained in the pores of a formation rock and are classified into three categories: • • •

Normal Subnormal Abnormal.

Formation pressure or pore pressure is said to be normal when it is caused solely by the hydrostatic head of the sub-surface water contained in the formations and there is pore to pore pressure communication with the atmosphere. Dividing this pressure by the true vertical depth gives an average pressure gradient of the formation fluid, normally between 0.433 psi./ft. and 0.465 psi./ft. The North Sea area pore pressure averages 0.452 psi./ft. In the absence of accurate data, 0.465 psi./ft., which is the average pore pressure gradient in the Gulf of Mexico, is often taken to be the ‘normal’ pressure gradient. NOTE:

The point at which atmospheric contact is established may not necessarily be at sea-level or rig site level.

Prior to a well intervention, all the well’s parameters are generally well known and the risk of encountering unexpected formation pressures is small. If there is any doubt over formation pressure, a BHP survey should be conducted as the first operation in the programme. 6.2.1 Sub-normal Formation Pressure Subnormal pressures occur in formations where the pressure gradient is less than ‘normal’. These are found mainly in mountainous areas or in producing formations where fluids have been extracted reducing the formation pressure. 6.2.2 Normal Formation Pressure Normal Formation Pressure is equal to the hydrostatic pressure of water extending from the surface to the subsurface formation.Thus, the normal formation pressure gradient in any area will be equal to the hydrostatic pressure gradient of the water occupying the pore spaces of the subspace formations in that area.

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The magnitude of the hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the formation water. Increasing the dissolved solids (higher salt concentration) increases the formation pressure gradient whilst an increase in the level of gases in solution will decrease the pressure gradient. For example, formation water with a salinity of 80,000 ppm sodium chloride (common salt) at a temperature of 25˚C has a pressure gradient of 0.465 psi./ft. Fresh water (zero salinity) has a pressure gradient of 0.433 psi./ft. Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion. In formations deposited in an offshore environment, formation water density may vary from slightly saline (0.44 psi./ft.) to saturated saline (0.515 psi./ft.). Salinity varies with depth and formation type. Therefore, the average value of normal formation pressure gradient may not be valid for all depths. For instance, it is possible that local normal pressure gradients as high as 0.515 psi./ft. may exist in formations adjacent to salt formations where the formation water is completely salt-saturated. 6.2.3. Abnormal pressure A pressure which is higher than the definition given for normal pressure is abnormal. The principal causes of abnormal pressures are: Under-compaction in shales When first deposited, shale has a high porosity. More than 50% of the total volume of uncompacted clay-mud may consist of water in which it is laid. During normal compaction, a gradual reduction in porosity accompanied by a loss of formation water occur as the thickness and weight of the overlaying sediments increase. Compaction reduces the pore space in shale, as compaction continues water is squeezed out. As a result, water must be removed from the shale before further compaction can occur. Not all of the expelled liquid is water, hydrocarbons may also be flushed from the shale. If the balance between the rate of compaction and fluid expulsion is disrupted such that fluid removal is impeded then fluid pressures within the shale will increase.The inability of shale to expel water at a sufficient rate results in a much higher porosity than expected for the depth of shale burial in that area. Salt Beds Continuous salt depositions over large areas can cause abnormal pressures. Salt is totally impermeable to fluids and behave plastically. It deforms and flows by recrystallisation. Its properties of pressure transmission are more like fluids than solids, thereby exerting pressures equal to the overburden load in all directions.The fluids in the underlying formations cannot escape as there is no communication to the surface and thus the formations become over pressured. © Aberdeen Drilling Schools 2001

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Mineralisation The alteration of sediments and their constituent minerals can result in variations of the total volume of the minerals present. An increase in the volume of these solids will result in an increased fluid pressure. An example of this occurs when anhydrite is laid down. If it later takes on water crystallisation, its structure changes to become gypsum, with a volume increase of around 35%. Tectonic Causes This is a compacting force that is applied horizontally in sub-surface formations. In normal pressure environments water is expelled from clays as they are being compacted with increasing overburden pressures. If however an additional horizontal compacting force squeezes the clays laterally and if fluids are not able to escape at a rate equal to the reduction in pore volume the result, will be an increase in pore pressure; See Figure 6.4. Faulting Faults may cause abnormally high pressures. Formation slippage may bring a permeable formation laterally against an impermeable formation preventing the flow of fluids. Nonsealing faults may allow fluids to move from a deeper permeable formation to a shallower formation. If the shallower formation is sealed then it will be pressurised from the deeper zone. Diapirism A salt diapirism is an upward intrusion of salt to form a salt dome. This upthrust disturbs the normal layering of sediments and over pressures can occur due to the folding and faulting of the intruded formations.

Extension

Extension Compression

Compression

Compression

Compression

Amount of Shortening

Possible Overpressured Zones

Figure 6.4 - Abnormal Formation Pressure Caused by Tectonic Compressional Folding 6-12


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Reservoir Structure Abnormally high pressures can develop in normally compacted rocks. In a reservoir in which a high relief structure contains oil or gas, an abnormally high pressure gradient as measured relative to surface will exist as shown in the following Figure 6.5.

Figure 6.5 - Reservoir Structure

Figure 6.5a Shows how the anticline differs from a dome in that it’s shape is long and narrow. Figure 6.5b Shows a simple structural trap. Figure 6.5c Shows stratigraphic trap. The size of the stratigraphical trap on the left is limited only by it’s hydrocarbon content while the one on the right is self limiting. © Aberdeen Drilling Schools 2001

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6.3 FORMATION FRACTURE PRESSURE The amount of pressure a formation can withstand before it splits is termed the fracture pressure. The pressure of fluid in a well must exceed formation pressure before the fluid can enter a formation and cause a fracture. Fracture pressure is expressed in psi., as a gradient in psi./ft., or as a fluid weight equivalent in ppg. In order to plan a conventional rig well intervention, it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as the fracture was initiated, followed by loss of workover fluid, loss of hydrostatic pressure, loss of primary well control and irreparable damage to the formation. Most operating companies have strict policies and procedures to ensure the fracture pressure is never exceeded (unless the formation was to be deliberately fractured for reservoir productivity improvement through sand fracing operations, etc.). Unless the service is to conduct remedial operations on or in the casing across the formation, it is preferred to isolate the formation from the kill fluid by installing a barrier or plug. Fracture pressures are related to the weight of the formation matrix (rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest.These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2 ppg then the overburden gradient is given by: 0.052 x 19.2 = 1.0 psi./ft. Since the degree of compaction of sediments is known to vary with depth, the gradient is not constant. Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0 psi./ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0 psi./ft. due to the effect of the depth of seawater and large thickness of unconsolidated sediment.

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6.4 FORMATION INTEGRITY TESTS To determine the fracture pressure of a formation, a leak-off test (LOT) or a formation integrity test (FIT) may be performed with a solids carrying fluid or mud. Where solids free workover fluids are used, a formation integrity test cannot be conducted and in these cases the formation is protected solely by a MAASP which is set at a safe percentage of the original casing pressure rating; Refer to Section 6.5. LOTs and FITs determine if the cement seal between the casing and the formation is adequate and the maximum pressure or fluid weight that the formation(s) can withstand without fracturing. As the leak-off test actually causes a fracture to determine the fracture gradient, it is rarely used in well servicing operations and the FIT is adopted. Whichever is to be performed, it must be ensured that the well is fully circulated to the correct weight workover fluid and the pump deliverability is sufficient. Leak-Off Test The test is performed by applying an incremental pressure from the surface to the closed wellbore/casing system until it can be seen that fluid is being injected into the formation. Leak-off tests should normally be taken to this leak-off pressure unless it exceeds the pressure to which the casing was tested. A typical procedure is as follows: • • • • •

• •

Before starting, gauges should be checked for accuracy.The upper pressure limit should be determined. The casing should be pressure tested before well operations commence. Circulate and condition the mud, check mud density in and out. Close BOPs. With the well closed in, the pump is used to pump a small volume at a time into the well typically a 1/4 or 1/2 bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped. Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped. Bleed off the pressure and establish the amounts of mud, if any, lost to the formation.

Examples of leak-off test plot interpretation: In non-consolidated or highly permeable formations fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown in Figure 6.6a will be obtained. Figure 6.6b and Figure 6.6c show typical plots for consolidated permeable and consolidated impermeable formations respectively.


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b) Consolidated Permeable Formations

Pressure

a) Unconsolidated Formations

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c) Consolidated Impermeable Formations

Final Pumping Pressure After Volume Increment Final Static PressureAfter Each Volume Increment Leak-Off Point

Pressure

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Figure 6.6 - Idealised Leak-Off Test Curves

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Formation Integrity Test An FIT can be performed when it is not acceptable to fracture a formation. In a FIT, fluid is pumped into the shut in well until a predetermined pressure is reached that is determined to be below the pressure to break down the formation. This value used is usually obtained by assessing information from well’s completion report and nearby well data. The procedure is: 1. 2. 3. 4. 5.

Before starting, gauges should be checked for accuracy. The casing should be pressure tested before well operations commence. Circulate and condition the mud, check mud density in and out. Close BOPs. With the well closed in, the pump is used to incrementally raise the pressure in the well to the test pressure and monitor the pressure to ensure that there is no leak off.

6.5 MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP With data from the formation integrity test, the maximum pressure which can be applied without fracturing the formation and the maximum fluid weight can be determined. The formation breakdown pressure =

Applied surface pressure + hydrostatic pressure of fluid in the casing

The applied surface pressure at which leak-off occurred or at FIT pressure, is the maximum allowable annulus surface pressure with the fluid weight in use at that time. MAASP is the maximum surface pressure that can be tolerated before reaching the formation fractures. MAASP

=

Formation breakdown pressure - HP of fluid in use at the formation

or re-written as: MAASP

=

(Fracture gradient - Fluid gradient) x TVD of formation

=

(Max. equivalent fluid weight - Fluid weight in well) x (0.052 x TVD of formation).

or as: MAASP

MAASP is only valid if the well is full of the original fluid during the LOT or FIT; if the fluid weight in the well is changed, MAASP must be recalculated. The calculated MAASP is no longer valid if influx fluids enter into the well.


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However, in practise MAASP is calculated as a percentage of the original casing burst pressure rating. This percentage is derived from experience and the age of the well casings, i.e. if the well is old and it is suspected there is casing corrosion or wear, the percentage will be lower than that of a more recently developed well. In general, the pressure rating is 80% of original burst. This pressure is used in the equation in place of the formation breakdown pressure.

6.6 CIRCULATING PRESSURE LOSSES Friction is resistance to movement. A force is required to overcome friction of a body or substance from a position of rest to movement. The amount of friction to overcome this resistance is dependent upon a number of factors: • • • • • • • •

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Density of the body or substance. Type of substance. Roughness of the surfaces making contact. Surface area in contact. Thermal and electrical properties. Direction of movement. Velocity. The force required to overcome friction is termed frictional loss.


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7. PRODUCTION WELL KILL PROCEDURES The most likely involvement of the use of well kill procedures during a live well intervention is to prepare it for a dead well workover. This entails killing the well by displacement of the well fluids from the completion tubing and sump to workover fluid. There are a number of kill procedures that are available depending on the circumstances that prevail such as tubing and casing integrity, ability to circulate the fluid in the annulus, formation pressure and characteristics of the completion methods and formation parameters that may control techniques such as reverse pumping into the formation. Individual wells must be evaluated to determine the most effective procedure. The most common well control methods are: • • • •

Reverse circulation Bullheading Lubricate and bleed. Deploying Coiled Tubing and displacing tubing.

As the completion tubing is normally full of well fluids and the tubing/casing annulus full of completion or packer fluid, then it is easier to conduct a reverse circulation kill as the gravities of the fluids will tend to keep them segregated as they are pumped up the tubing.The preferred method is to install a wireline set plug as low as possible in the well below the packer (e.g. packer tailpipe), if possible, to isolate the formation from the kill fluid, and then reverse circulate to kill the well. Bullheading is only recommended where it causes no damage to the formation and some operators have strict policies stating if, and under what conditions, this method may be used. Lubricate and bleed is the least preferred and is only used when there is some obstacle to conducting the other methods. For instance, it may be a combination of an obstruction in the tubing which prevents the running of wireline to open a circulating path (e.g. a partially closed valve) and a blockage or tight formation preventing bullheading. 7.1 WELL PREPARATION Prior to initiating well killing operations, several safety precautions must be exercised. The well must be shut-in in advance of operations to stabilise bottomhole pressure and allow time to inspect and service the Xmas tree. The tree valves and sub-surface safety valves should be tested to ensure they comply with API criteria. Where practicable, each annulus should be checked for H2S and any found dealt with. The well shall then be isolated from all external control systems, the lines isolated by double barrier isolation and depressurised. The only exception is during kill operations when hydrocarbons are being flowed to the production system.


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IWCF WELL INTERVENTION PRESSURE CONTROL PRODUCTION WELL KILL PROCEDURES

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7.2 REVERSE CIRCULATION This kill method is the safest, and probably the simplest, as it uses the natural U-tubing effect, of the different gravities of fluids in the annulus and tubing, to flow the well fluids out through the Xmas tree choke and existing flowlines to the production facilities. The only pump pressure required is to equalise across the circulation device before opening and, when the kill fluid is near in balance tubing-to-tubing/casing annulus and circulating friction losses need to be overcome. This method requires a circulation path between the tubing and tubing/casing annulus to be opened by operating a circulation device in the completion string or punching a hole with wireline.The procedure is even more effective if a plug can be installed to isolate the completion/ packer and kill fluid from the formation, but this is dependent upon the whether or not operations are to be carried out below this point. If there is no plug, the old dirty completion/ packer fluid may contaminate the formation if losses occur before the clean kill fluid gets around into the tubing. The well is circulated with a back pressure maintained on the tubing so that a constant bottomhole pressure can be maintained so as to eliminate any further flow of reservoir fluids into the well. In other words, maintaining a hydrostatic head on a formation that is greater than the actual formation pressure, but obviously one that is not too much greater, otherwise there will be excessive fluid loss, or even fracturing of the formation. To prevent any further inflow of formation fluids it is common practice to maintain a tubing pressure that is some 200 psi. higher than the shut-in pressure. This will ensure that when pumping is started, the kill fluid pressure on the formation will be higher than the formation pressure. As the kill fluid is pumped to the tubing the surface pressure can be slowly reduced in proportion to the amount of fluid rise in the tubing. One of the main reasons for using the reverse circulation method is that it is easier to pump maintaining oil and/or gas on top of the kill fluid than it is to force the oil and gas down below the kill fluid.There is as a result far less contamination of the kill fluid with well fluids, and there is less of a problem in establishing a clean kill fluid for circulation. The slightly higher hydrostatic head on a formation is maintained during the kill operation reducing the chance of influx of the formation fluids. As the kill fluid moves up the tubing, the back pressure held on the tubing head is reduced. This can be shown in the form of a graph with tubing head pressure against time (assuming a constant pumping rate) or tubing head pressure against quantity pumped; See Figure 7.1. The operator on the choke will reduce pressure in accordance with the graph which is based on tubing capacity and the pumping rate. If there is a fluctuating pump rate then there will have to be communication between the pump operator and the operator on the tubing head so that the pressure is reduced at the correct rate. The reverse circulation method can be used for all types of wells except possibly those with very high production rate and very low reservoir pressure. In this case it is not possible to have a kill fluid of sufficiently low hydrostatic head to kill the well without heavy losses or where it is not possible to fill the tubing without exceeding the reservoir pressure. 7-2


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An alternative method of using a circulation kill method is to use coiled tubing which can be run into the well under pressure.The well can then be killed by pumping mud down the small bore coiled tubing and back up the tubing/coiled tubing annulus. The procedure is the same as for the reverse circulation kill though, of course, this is actually a forward circulation procedure. The back pressure is held as before on the tubing to control the bottomhole pressure. This method would be used where it was not possible to establish communication around the tubing shoe or through a sliding sleeve, and where it is not desirable to bullhead.

TUBING PRESSURE (PSI)

Tubing Volume

BARRELS PUMPED

Figure 7.1 - Typical Reverse Circulation /Tubing Pressure Chart


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7.2.1 Example Of A Reverse Circulation (No Tubing Plug Installed) Consider the following scenario: • • • • • • • • •

Vertical land well completed 7 years previous. Closed in tubing head pressure 1,725 psi. Closed in annulus head pressure 1,725 psi. Inhibited water in annulus of gradient 0.435 psi./ft. Production casing 7 ins, 38 lbs./ft. C75 HC-Packer at 8,000 ft. Production tubing 31/2 ins. 12.6 lbs./ft. C75 VAM. Gas lift mandrel installed at 5,600 ft. for gas lift assist. Perforations at 8,250 ft. just below packer.

The annulus gas lift pressure was bled off to zero in preparation for the annulus to be filled with water. However, the annulus pressure increased again to its initial value in 18 hours indicating a leak in the tubing.Wireline services retrieved the sub-surface safety valve (SCSSV) and run a gauge ring to the landing nipple below the production packer. A dummy safety valve was set in the SCSSV landing nipple and no increase in annulus pressure was observed when the annulus pressure was bled down indicating the leak was at the SCSSV. Attempts to set a plug below the packer failed possibly due to corroded tubing. Wireline identify the location of tubing fluids as follows: • •

Gas (0.1 psi./ft.) - 5,250 ft. to surface. Oil (0.4 psi./ft.) - 8,250 to 5,250 ft.

Generate an appropriate procedure to kill the above well ensuring that the BHP does not exceed the reservoir pressure by 150 psi. and construct a kill graph.

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Step 1: Calculate The Annulus and Tubing Capacities Using tables: a)

Capacity of 7 ins. casing (38 lbs./ft.) =

b) c)

0.0119 bbls./ft.

Capacity of 7 ins. x 31/2 ins. annulus =

d)

0.034 bbls./ft.

Closed end displacement of 31/2 ins. tubing =

0.0340 – 0.0119

=

0.0221 bbls./ft.

Capacity of 31/2 ins. tubing (12.7 lbs./ft.) =

0.0073 bbls./ft.

Step 2: Calculate The Well Volumes a)

Tubing volume above packer =

b)

8,000 x 0.0221

=

58.4 + 176.8

=

176.8 bbls. 235.2 bbls.

Volume of oil in tubing above packer (8,000 – 5,250) x 0.0073 =

e)

58.4 bbls.

Total well volume above packer =

d)

=

Annulus volume above packer =

c)

8,000 x 0.0073

20.07 bbls.

Volume of oil in tubing to perfs. (8,250 – 5,250) x 0.0073 =

NOTE:

21.90 bbls.

It is expected that most of the tubing oil below the packer will be displaced by annulus fluid (0.435 psi./ft.) filtering through to the perforations.


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1725 psi

1725 psi

5250 ft 5600 ft

8000 ft gas lift valve in SPM

0.1 Gas

0.433 Brine

0.435 Brine

0.4 Oil

(Gradients in psi / ft)

Figure 7.2 - Initial Well Status 7-6


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Step 3: Calculate The Required Kill Fluid Weight To Balance Reservoir Pressure a)

Pres

b)

Kill fluid gradient

=

1,725 + 5,250 x 0.1 +3,000 x 0.4 =

3,450 ––––– 8,250

=

3,450 psi. at perforation.

=

0.418 psi./ft.

and hence fresh water (gradient 0.433 psi./ft.) can be used to kill the well as it provides a hydrostatic pressure of 3,572psi Step 4: Determine The Kill Plan Since it takes 18 hours for pressure equalisation between the tubing and annulus, the tubing leak must be small. Since a gas lift mandrel was set at 5,600 ft. it seems likely that the fluid level in the annulus is at this depth. The preferred method to kill the well is a reverse kill method. Therefore holes must be punched in the tubing as close as possible to the packer; this can be performed using wireline techniques using explosive tubing perforators. Tentative well kill plan: 1. 2. 3. 4. 5. 6. 7. 8.

Connect one side outlet of the tubing head spool (THS) to a pump with a pressure rating of at least 5,000 psi.; this can be a cement pump. Connect the other side outlet of the THS to a choke manifold. Install a wireline lubricator on to the Xmas tree. Pressure test all surface equipment as per company policy. Connect the suction line of the pump to the kill fluid tank of sufficient capacity; in this case a minimum of 300 bbls. will be required. Connect the outlet of the choke manifold to a separator and the outlet of this separator to the kill fluid tank. Calibrate the brine tank and install a level indicator. Start the pump and open the choke. Manipulate the choke in such a way that the annulus pressure remains initially at 1,725 psi.

Every barrel of kill fluid pumped into the annulus represents an equivalent height of: 1 –––––– = 45.2 ft. 0.0221 which provides a hydrostatic head of 45.2 x 0.433 = 20 psi. The increase in hydrostatic pressure in the annulus will be 20 – 45.2 x 0.1 = 15 psi. The volume of kill fluid to fill the annulus (assumed initial level of 5,600 ft.) will be 5,600 x 0.0221 = 124 bbls. © Aberdeen Drilling Schools 2001

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This implies that the annulus pressure will need to be reduced by 15 psi. for every barrel of kill fluid that fills the annulus. 9.

10. 11. 12. 13. 14.

Monitor the volume of kill fluid in the tank continuously. The choke must be manipulated such that the annulus pressure (pump pressure) will drop by the calculated amount (15 psi.) for every barrel lost to the annulus. Keep circulating and manipulating the choke until the entire annulus is filled with kill fluid. Connect the choke manifold to the production side outlet of the Xmas tree. Pressure test all connections as per company policy. Connect the outlet of the separator to an empty tank of sufficient capacity. In this case a minimum of 100 bbls. will be sufficient. Perforate the tubing just above the packer.

Hydrostatic pressure in annulus at tubing holes: 5,600 x 0.433 + (8,000 – 5,600) x 0.435

=

3,469 psi.

=

3,350 psi.

Hydrostatic head in tubing at holes: 1,725 + 5,250 x 0.1 + (8,000 – 5,250) x 0.4

Differential pressure will be 3,469 – 3,350 = 119 psi. which could cause problems during wireline operations. 15.

16. 17. 18.

7-8

Start pumping kill fluid into the annulus such that the THP follows the calculated kill graph which ensures that the bottomhole pressure will be equal to or slightly above the reservoir pressure. Continue circulating until the well is filled with kill fluid. Check for fluid losses. If severe losses are observed then consideration should be given to acid degradable LCM materials as a kill fluid additive or a cement plug installed. Check that the well does not flow.


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1725 psi

0 psi

5250 ft 5600 ft

8000 ft

0.1 Gas

0.433 Brine

0.435 Brine

0.4 Oil


Figure 7.3 - Circulating Start Point © Aberdeen Drilling Schools 2001

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Step 5: Constructing The Kill Graph The THP at the start of the kill operation will be 1,725 psi. and this pressure should drop off fairly rapidly as water (0.435 psi./ft.) enters the tubing and gas leaves the tubing at surface. Calculate the pressure when oil reaches the surface. a)

Height of oil in tubing

= 3,000 ft o

b)

Height of water (0.435 psi./ft.) in tubing above packer = 5,000 ft.

c)

Volume of water (0.435 psi./ft.) in the tubing above packer = 5,000 x 0.0073

d)

= 36.50 bbls.

Hydrostatic pressure of tubing contents at perforations = 5,250 x 0.435 + 3,000 x 0.4 = 3,484 psi.

which is higher than the reservoir pressure (but not higher than 150 psi.) indicating that the well should be dead before the oil reaches the surface. e)

Height of water in the tubing above perforations

= 8,250 – 3,000 – Htgas = 5,250 – Htgas.

Total hydrostatic head in the tubing = 0.1 x Htgas + 3,000 x 0.4 (5,250 – Htgas) x 0.435 which should equal the reservoir pressure. 0.1 x Htgas + 3,000 x 0.4 + (5,250 – Htgas) x 0.0345 Solving for Htgas yields The height of the water in the tubing will be The volume of water in the tubing will be

= 3,450 psi. Htgas = 64 ft.

5,250 – 64 = 5,186 ft. 5,186 x 0.0073

= 37.86 bbls.

Thus the well will be dead after pumping 37.86 bbls. of kill fluid into the annulus and the choke at the tubing outlet can be fully opened and circulation of the entire well performed with fresh water of volume 242.5 bbls.

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0 psi

0 psi

2750 ft

8000 ft

0.1 Gas

0.433 Brine

0.435 Brine

0.4 Oil


Figure 7.4- Oil at Surface © Aberdeen Drilling Schools 2001

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The graph for the annulus reduction in pressure and the kill graph for the tubing pressure are shown in Figure 7.4.

2000

2000

Annulus

Tubing

1725 1500

1725 1500

500

bbls

bbls

37.86

500

30

1000

10

1000

20

psi

psi

10 20 30 40 50 60 70 80 90 100 110 124 120 130

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Figure 7.5 - Annular Pressure Reduction and Tubing Pressure Kill Graphs

7.2.2 Bullheading or Squeeze Kill This method consists of pumping kill fluid to the well and forcing the well fluids back into the formation without pumping at a rate which will fracture the formation, the latter being somewhat difficult when trying to kill a well with fracture production. This method is the only method possible when a well has been completed without tubing. It can also be used when the tubing has been landed in a packer and the circulation devices, such as a sliding sleeve, has jammed.This would mean that it is not possible to establish circulation around the tubing shoe or near the tubing shoe (other than by perforating the tubing). In this method the pump rate has to be high enough to ensure that the rate the kill fluid is moving down the tubing is faster than it will free fall. This will prevent the contamination of the kill fluid by oil in an oil well, and gas cutting in a gas well. In effect, a piston effect is required so that the kill fluid is going down the tubing as a piston sweeping all the well fluids before it: An example of a bullhead/squeeze kill is shown in Figure 7.5.

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Normally this method only finds use in wells with small tubings and with high permeabilities allowing adequate pumping rates. In larger tubings (31/2"+) and in low permeability wells, this method is time consuming and difficult, resulting in gas cutting of the kill fluid especially in gas wells and wells with high gas/oil ratios.This method also has the potential draw back in that some of the kill fluid is inevitably pumped away to the formation.

Displaced Tubing Tubing Burst Limit

10570

10000

8000 7013

Maximum Allowable Static Tubing Pressure for Formation Fracture

3457

Static Tubing Displacement Pressure

psi 6000

4000

60

50

40

30

20

10

2000

bbls

Figure 7.6 - Typical Bullheading Pressure Chart


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7.2.3 Lubricate and Bleed For a gas well, or gas filled tubing, an alternative method is to use the lubrication kill. In this method varying amounts of mud are lubricated into the well, and the well pressure is bled off after each batch of mud has been lubricated into the well. The method consists of the following steps: Calculate the capacity of the tubing and pump half this volume of kill fluid to the well. Observe the well (1/2 to 1 hour), the tubing head pressure will drop due to the hydrostatic head of the initial kill mud pumped.When the tubing head pressure is constant, the next step is taken. Pump kill fluid for about 3 - 5 minutes, and not more than about 10 barrels, and making sure that the tubing head pressure does not go more than 200 psi. above the observed static pressure taken in step 2. Bleed off gas from the tubing at a high rate immediately after pumping the batch of kill fluid. The amount of drop in tubing head pressure could be equal to the amount of hydrostatic head of the mud pumped. If the bleeding off is not carried out quickly, the additional pressure due to the extra hydrostatic head will cause mud losses and the sooner the tubing head is reduced, the smaller the loss will be. Repeat the pump and bleed and observe the tubing head pressure after each step. If necessary, reduce the quantity of kill fluid if the amount of gas being bled off is excessive. After repeated pumping of batches of mud and the well is deemed dead, observe the well for a considerable period before starting and further work. If the fluid level is too low, then the kill fluid has been too heavy and additional lighter fluid should be added until the well is full of fluid. Alternatively, if the well will not die, it could be that too much gas was bled off or some of the kill fluid was blown out of the well during the bleed off cycle, resulting in gas flowing into the well bore. Wait for the well to settle and after re-appraising the situation, carry on with the batch and bleed procedure until the well is completely dead.

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8.1

GENERAL

8.2

SNUBBING OPERATIONS

8.3

WIRELINE OPERATIONS

8.4

COILED TUBING OPERATIONS

8.5

SUBSEA WELL INTERVENTIONS

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8. WELL CONTROL EQUIPMENT 8.1 GENERAL This section illustrates the various well control systems and equipment used with the various well intervention methods described in Section 3 and well control methods in Section 6. 8.2 SNUBBING OPERATIONS An HWO unit is utilised on both live well interventions and dead well workovers. When utilised on workovers, the well control is similar to a rig operation, requiring the well to be killed and plugged and the Xmas tree replaced by a BOP stack on the casing head. The only difference in well control equipment may be in the workstrings used where check valves may be installed to the BHA as additional primary well control. In place of the rig circulation system, pumps, tankage, mixing hoppers and hard piping would have to be provided unless the operation was rig assisted. However, when used in snubbing operations, the pressure control systems are significantly different.The equipment used for snubbing operations is described in the sub-section below. 8.2.1 Snubbing Operations Snubbing operations with an HWO unit entails installation of the well control equipment onto the top of the Xmas tree for ‘through-tubing’ work. BOP configurations for snubbing operations are shown in Section 7.2.2 below. The arrangements shown illustrate stripping pipe rams for running collared pipe but an annular preventer can be used when running nonupset or tapered connections such as Hydril PH6, etc. Workstring BHAs also contain barrier systems for primary and secondary pressure control. NOTE:

The snubbing configurations shown are generic and may not conform to individual service companies’ policy and procedures.There is no API standard for snubbing well control equipment and development of the method has been driven by the users.The configurations listed meet the absolute minimum and it would be common practice for additional safety to be added.

An equalising loop must be used when stripper rams are being used but is not necessary when using annular preventers on non-upset pipe or pipe with tapered upset connections. Equalising loops should be constructed with flanged connections.


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IWCF WELL INTERVENTION PRESSURE CONTROL WELL CONTROL EQUIPMENT

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8.2.2 Snubbing BOP Arrangements - 0 - 5,000 psi. WP Operating features: 1. 2. 3. 4. 5.

8-2

This is the very minimum arrangement for 0 - 5,000 psi.WP and one size of pipe only. If a leak occurs to either of the strippers, both pipe rams would be closed to allow repair and re-instatement of the strippers. Two pipe rams provide block and bleed. Two tree valves must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial. The pipe rams should not be used for stripping unless in an emergency situation. When the upper pipe rams are closed, the flow line and chokes can be used.


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Minimum 4 1/6” 10M BOP Snubbing Stack For 0 -5000 psi One Pipe Size Only

Bleed Off Strippers To Pump Line Safety

Choke

The Wellhead must have a minimum of two functional blind BOP’s, gate valves or a combination of both

Figure 8.1 - Example Snubbing BOP RAM Configuration © Aberdeen Drilling Schools 2001

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8.2.3 Snubbing BOP Stack Arrangements - 5,000 - 10,000 psi. WP Operating features: 1. 2. 3.

4. 5. 6.

7.

8-4

This is the very minimum arrangement for 5,000 - 10,000 psi.WP and one size of pipe only. If a leak occurs to either of the strippers, both the pipe rams would be closed to allow repair and re-instatement of the strippers. Two tree valves or a combination of both tree valves and blind rams must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial. When the upper-pipe or blind rams are closed, the flow line and chokes can be used. The pipe rams should never be used for stripping unless in an emergency situation. With drill pipe in the hole, the blind rams can be changed to pipe rams and the drill pipe can be reciprocated through the upper rams while retaining the two bottom rams in reserve. The combination of shear and blind rams provide ultimate safety, if secondary well control fails.


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Minimum BOP stack for 5000 - 10,000 psi One pipe size use All flanged valves and loop

Bleed Off Strippers To Pump Line Safety Safety Choke Shear Hydraulic Controlled

Sensor

Safety



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8.2.4 Snubbing BOP Stack Arrangements - Over 10,000 psi. WP Operating features: 1. 2. 3.

4. 5. 6.

8-6

This is the very minimum arrangement for over 10,000 psi. WP and one size of pipe only. If a leak occurs to either of the strippers, both the pipe rams would be closed to allow repair and re-instatement of the strippers. Two tree valves or a combination of both valves and blind rams must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial. When the upper pipe or blind rams are closed, the flow line and chokes can be used. The upper pipe rams can be used for stripping in an emergency situation. The combination of shear and blind rams provide ultimate safety, if secondary well control fails.


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Minimum BOP stack for pressure over 10,000 psi One pipe size use All valves and loop are flanged

Bleed Off Strippers To Pump Line Safety Blind To Kill Line Shear Safety

Choke Sensor

Safety



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8.2.5 Snubbing BHA Arrangements The BHA shown is typical and must be accompanied by having a safety valve on hand in the work basket. Operating features: 1. 2.

3. 4. 5.

There should be a minimum of two check valves. At least one wireline nipple must be installed for secondary well control. If a leak occurs to either of the check valves, a wireline run check valve can be installed in this nipple. Enough distance must be provided, especially in sandy conditions so the both check valves can be plugged. Spacing out of the check valves must be such that they can be snubbed into the well above two closed barriers. A tubing leak above the check valves, secondary control is provided by stabbing on the safety valve in the work basket.

Various configurations may be used for differing applications providing they meet with the minimum requirements outlined above.

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Minimum BOP stack for pressure over 10,000 psi One pipe size use (With Restrictor spool for 1”) All valves are flanged

Bleed Off Strippers To Pump Line Safety

Blind Choke

Hydraulic Controlled

Sensor Shear Safety Safety The Wellhead must have a minimum of two functional blind BOP’s, gate valves or a combination of both


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8-10

STANDARD BPV CONFIGURATIONS BPV

SINGLE JOINT

SINGLE JOINT

SINGLE JOINT

LANDING NIPPLE

SECONDARY

LANDING NIPPLE

SECONDARY

LANDING NIPPLE

WORK STRING

WORK STRING

WORK STRING

D

PUMP OUT BPV

PRIMARY

BPV

BPV

WORK STRING

C

SINGLE JOINT

PRIMARY

PUP JOINT 6 FT LONG

SECONDARY

LANDING NIPPLE

WORK STRING

B

BHA

BPV

BHA

BPV

SECONDARY

LANDING NIPPLE

A

SINGLE JOINT

PRIMARY

SINGLE JOINT

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NON-STANDARD BPV CONFIGURATION

Figure 8.5 - BHA Configurations


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8.3 WIRELINE OPERATIONS Most well servicing is accomplished using wireline methods which are relatively simple to rig up and conduct operations, compared to other methods.The development of wireline pressure control systems have made this service one of the safest in the industry. Braided line (i.e. electric line and swab line) and slickline pressure control equipment is similar in design and operation but do have some differences which are outlined below. 8.3.1 Slickline Lubricator/Single BOP Stack Arrangement Operating features: 1. 2. 3. 4.

The stuffing box is adjustable (manually, or more commonly hydraulically) to cater for packing wear. The lubricator is an intrinsic part of the primary well control system along with the stuffing box. If the stuffing box leaks, the wireline BOP wire/blind rams can be closed on the wire to repair the packing. If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.

8.3.2 Slickline Lubricator/Dual BOP Stack Arrangement Operating features: 1. 2. 3. 4. 5. 6.

The stuffing box is adjustable (manually, or more commonly hydraulically) to cater for packing wear. The lubricator is an intrinsic part of the primary well control system along with the stuffing box. If the stuffing box leaks, the upper wireline BOP wire/blind rams can be closed on the wire to repair the packing. If the upper rams leak, the lower rams can be used. If the wire is broken and expelled from the lubricator, both rams can be closed to provide double isolation. If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.


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SHEAVE STUFFING BOX

LUBRICATOR SECTIONS

LUBRICATOR SECTIONS

SLICKLINE LUBRICATOR AND BOP

Figure 8.6 - Slickline Lubricator and BOP 8-12


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SHEAVE STUFFING BOX

LUBRICATOR SECTIONS

LUBRICATOR SECTIONS

BLIND RAMS

WIRELINE RAMS

Figure 8.7 - Slickline Lubricator and Dual BOP © Aberdeen Drilling Schools 2001

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8.3.3 Braided Line Lubricator/Dual BOP Stack Arrangement Operating features: 1. 2. 3. 4. 5.

8-14

The grease seal pressure is adjustable for varying well pressures. The lubricator is an intrinsic part of the primary well control system along with the grease seal. If the grease seal fails, both the wireline BOP wire rams can be closed on the wire.The lower ram is inverted so that grease can be injected to create a seal. If the wire is broken and expelled from the lubricator, two Xmas tree valves must be closed to provide double isolation. If the rams leak, the wire can only be cut with a wire cutting actuator.


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HYDRAULIC PACKING NUT STUFFING BOX FLOW TUBE FLOW TUBE GREASE CONNECTION

LUBRICATOR SECTIONS

LUBRICATOR SECTIONS

BLIND RAMS

INVERTED WIRELINE RAMS

Figure 8.8 - Braided line Lubricator and Dual BOPs © Aberdeen Drilling Schools 2001

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8.3.4 Electric Line Lubricator/Triple BOP Stack Arrangement Operating features: 1. 2. 3. 4. 5.

8-16

The grease seal pressure is adjustable for varying well pressures. The lubricator is an intrinsic part of the primary well control system along with the grease seal. If the grease seal fails, both the wireline BOP wire rams can be closed on the wire.The lower ram is inverted so that grease can be injected to create a seal. If the wire is broken and expelled from the lubricator, the blind ram plus a Xmas tree valves must be closed to provide double isolation (or two tree valves). If the rams leak, the wire can only be cut with a wire cutting actuator.


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LINE WIPER PACK OFF HYDRAULIC CONNECTION GREASE CONNECTION (GREASE OUT)

GREASE CONNECTION (GREASE IN) FLOW TUBE

TOOL CATCHER

LUBRICATOR SECTION

HYDRAULIC TOOL TRAP

QUICK UNION

TRIPLE BOP

WELLHEAD ADAPTER

Figure 8.9 - Electric Line Lubricator and Triple BOP © Aberdeen Drilling Schools 2001

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8.4 COILED TUBING OPERATIONS Coiled tubing operations are very similar in method to snubbing operations, except that the C/T unit uses an injector head with travelling chains instead of a hydraulic jacking unit. The BOP stack, however is simplified due to the coiled tubing being of smaller diameter and nonupset allowing a stripper to be used. Specialised BOPs have also been developed with gripper rams to cater for easier pipe retrieval if ever the pipe is sheared. C/T operations are generally limited to a maximum of 5,000 psi., although this may be increased in future through new tubing technology. Most C/T operations now use quad BOPs. All C/T BHAs include double check valves for inside primary pressure control except in very special circumstances. 8.4.1 C/T Standard BOP Configuration Operating features: 1. 2. 3. 4.

The stripper is adjustable for well pressure up to 5,000 psi. If the stripper fails, the pipe rams can be closed to allow repair. If the tubing is broken and falls downhole, the blind ram are closed with an Xmas valve provided the tubing is clear of the tree. If the rams leak, the tubing can be cut with the shear rams and the blind rams closed. The tubing is held in place with the slip rams to aid in recovery, hence the tree valves cannot be used.

8.4.2 C/T BOP Configuration with Shear/Seal BOP Operating features: 1. 2. 3. 4.

5.

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The stripper is adjustable for well pressure up to 5,000 psi. If the stripper fails, the pipe rams can be closed to allow repair. If the tubing is broken and falls downhole, the blind rams are closed with an Xmas valve providing the tubing is clear of the tree. If the rams leak, the tubing can be cut with the shear rams and the blind rams closed. The tubing is held in place with the slip rams to aid in recovery, hence the tree valves cannot be used. Tertiary well control is provided by the shear/seal BOP and is the final and last resort in the event of secondary well control failure.


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Figure 8.10 - Standard C/T BOP Configuration © Aberdeen Drilling Schools 2001

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Figure 8.11 - C/T BOP Configuration with Shear Seal BOP 8-20


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8.5 SUBSEA WELL INTERVENTIONS Subsea wells can be serviced by means of subsea workover systems. There are two systems in current use, one for conventional susbsea trees and the other for the newer generation of spool trees. The former is described in Section 8.5.1 below and the latter in 8.5.2. 8.5.1 Conventional Subsea Well Interventions Conventional subsea well interventions are conducted through a subsea workover riser systems which are deployed from floating vessels or from jack-up rigs in shallower waters. Riser systems are attached to the top of subsea Xmas trees and, after completing the appropriate test procedures, allow live well servicing by wireline or coiled tubing methods. Pressure control is provided at surface by a Xmas tree fitted with a lift frame which accommodates the pressure control equipment installed on the top of the tree. Other than this, pressure control is exactly the same as that described in the previous sections except that vessel movement gives additional rigging up and operational problems. However, the workover riser system must also have subsea pressure control capabilities in the event of a emergency disconnection or a riser failure. Subsea pressure control is provided by a subsea lower riser assembly (LRA) and an emergency disconnect package (EDP) which can safely close in the well and disconnect the riser, with or without wireline or coiled tubing through the subsea tree, in the event of an emergency. These systems maintain the well in a safe condition until the problems arisen are overcome and the riser can be re-attached. Operations can then be recommenced and fishing operations initiated, if required. A typical subsea workover riser system is shown in Figure 8.12 8.5.2 Spool Subsea Tree Interventions Due to the capital costs of conventional workover riser systems, and the incompatability between the various manufacturer’s designs, this drove the industry to develop the spool tree and associated intervention systems utilising standard drilling rig subsea BOP riser systems. The subsea BOPs were utilised for connection to the tree and to provide pressure control in conjunction with a subsea test tree which latches onto the spool tree tubing hanger. Pressure is contained within the subsea tree and it’s riser to the surface which is terminated with a surface test tree in the conventional well test fashion.The BOP rams are closed on the subsea test tree slick joint to provide a barrier to any well pressure below the BOPs. In the event of an emergency, the subsea tree can be closed, the subsea riser disconnected before the BOP shear/blind rams are closed above the tree valve section and the drilling riser disconnected. The main problem thrown up by this method of well intervention was the lack of bore size in standard subsea test tree riser systems initially available which has driven the design of systems with bores sizes now up to 7 inches in diameter.


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Subsea test tree systems must have a cutting capability to sever any wireline or coiled tubing run through the BOPs. See Figure 8.13 for typical spool tree workover system.

Figure 8.12 - Typical Subsea Workover Riser System 8-22


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Figure 8.13 - Typical Subsea Spool Tree Workover System © Aberdeen Drilling Schools 2001

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APPENDIX A

A.

FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL

A.1

CONVERSION FACTORS

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A. APPENDIX - FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL Pressure Gradient psi/ft. Mud/Brine Weight ppg x 0.052 Mud/Brine Weight ppg Pressure Gradient psi/ft ÷ 0.052 Hydrostatic Pressure psi Mud/Brine Weight ppg x 0.052 x True Vertical Depth ft Formation Pressure psi Hydrostatic Pressure (in string & sump) psi + Shut In Tubing Head Pressure psi Equivalent Mud Weight ppg Pressure psi ÷ True vertical Depth ft ÷ 0.052 Pump Output bbls/min Pump Output bbls/stk x Pump Speed spm Annulus Velocity ft/min Pump Output bbls/min ÷ Annulus Volume bbls/ft Boyle’s Law P1V1 = P2V2 Conversion of pipe diameter to bbls/ft

A.1 CONVERSION FACTORS Acre Atmosphere

Bar Barrel


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= 43,560 square feet = 4,047 square metres = 33.94 feet of water = 29.92 inches of mercury = 760 millimetres of mercury = 14.70 pounds per square inch = 14.504 pounds per square inch = 100 Kilo Pascal’s = 5.6146 cubic feet = 42 gallons (US) = 35 gallons (Imperial)

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Barrel of water @ 60˚F Barrel (36˚ API) Barrel per hour

Barrel per day (bopd) British Thermal Unit BTU per minute Centimetre Centimetre of mercury Cubic centimetre Cubic foot

Cubic foot per minute

Cubic inch Cubic metre

Cubic yard

Feet Feet of water @ 60˚F Feet per second Foot pound Foot pound per second Gallon (US)

Gallon (Imperial) Gallon per minute Gram

A-2

= 0.1588 metric ton = 0.1342 metric ton = 0.0936 cubic feet per minute = 0.700 gallon per minute = 2.695 cubic inches per second = 0.2917 gallon per minute = 0.2520 kilogram calorie = 0.2928 watt hour = 0.02356 horse power = 0.3937 inch = 0.1934 pound per square inch = 0.06102 cubic inch = 0.1781 barrel = 7.4805 gallons (US) = 0.02832 cubic metre = 0.9091 sacks cement (set) = 10.686 barrels per hour = 28.800 cubic inches per second = 7.481 gallons per minute = 16.387 cubic centimetres = 6.2897 barrels (US) = 35.314 cubic feet = 264.20 gallon (US) = 4.8089 barrels = 46,656 cubic inches = 0.7646 cubic metre = 30.48 centimetres = 0.3048 meters = 0.4331 pound per square inch = 0.68182 mile per hour = 0.001286 British Thermal Unit = 0.001818 horse power = 0.2318 barrel = 0.1337 cubic feet = 231.00 cubic inches = 3.785 litres = 0.003785 cubic metres = 1.2009 gallons (US) = 277.274 cubic inches = 1.429 barrels per hour = 34.286 barrels per day = 0.03527 ounce


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Pressure Quart (Liquid) Sack cement (Set) Square centimetre Square foot Square inch


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= 42.44 BTUs per minute = 33,000 feet/pounds per minute = 550 feet/pounds per second = 1.014 horsepower (metric) = 0.7457 kilowatt = 2,547 British Thermal Units = 2.540 centimetres = 1.134 feet of water = 0.4912 pound per square inch = 0.0361 pound per square inch = 2.2046 pounds = 3.968 British Thermal Units = 14.223 pounds per square inch = Kg/cm2 x 98.1 gives Pascals (KPa) = 3,281 feet = 0.6214 mile = 0.145 pounds per square inch = 1.341 horse power = 0.2462 gallon = 1.0567 quarts = 145.03 pound per square inch = 3.281 feet = 39.37 inches = 5,280 feet = 1.609 kilometres = 1.4667 feet per second = 28.3495 grams = 0.05835 grain per gallon = 8.345 pounds per million gallons = 0.000145 pound per square inch = 7,000 grains = 0.4536 kilogram = 2.309 feet of water @ 60˚F = 2.0353 inches of mercury = 51.697 millimetres of mercury = 0.703 kilograms per square centimetre = 0.0689 bar = 0.006895 mega Pascal (MPa) = 6.895 kilo Pascal (KPa) = 6895 Pascal (Pa) = psi x 6.895 gives Kilo Pascals (KPa) = 0.946 litre = 1.1 cubic feet = 0.1550 square inch = 0.929 square metre = 6.452 square centimetres A-3

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Square kilometre Square metre Square mile Temp Centigrade Temp Fahrenheit Temp Absolute (Kelvin) Temp Absolute (Rankine) Ton (long) Ton (metric) Ton (short or net) Ton (metric) Ton (metric)

Ton (short or net) Watt per hour Yard

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= 0.3861 square mile = 10.76 square feet = 2.590 square kilometres = 5/9 (Temp ˚F - 32) = 9/5 (Temp ˚C) + 32 = Temp ˚C + 273 = Temp ˚F + 460 = 2,240 pounds = 2,205 pounds = 2,000 pounds = 1.102 tons (short or net) = 1,000 kilograms = 6.297 barrels of water @ 60˚F = 7.454 barrels (36˚ API) = 0.907 ton (metric) = 3.415 BTUs = 0.9144 metre


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GLOSSARY FOR WELL CONTROL OPERATIONS

B.1

COMMONLY USED WELL CONTROL TERMS

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GLOSSARY FOR WELL CONTROL OPERATIONS

B.1 COMMONLY USED WELL CONTROL TERMS Abnormal Pressure

Pore pressure in excess of that pressure resulting from the hydrostatic pressure exerted by a vertical column of water salinity normal for the geographic area.

Accumulator

A vessel containing both hydraulic fluid and gas stored under pressure as a source of fluid power to operate opening and closing of blowout preventer rams and annular preventer elements.Accumulators supply energy for connectors and valves remotely controlled.

Accumulator Bank Isolator Valve

The opening and closing device located upstream of the accumulators in the accumulator piping which stops flow of fluids and pressure in the piping.

Accumulator Relief Valve

The automatic device located in the accumulator piping that opens when the pre-set pressure limit has been reached so as to release the excess pressure and protect the accumulators.

Air Regulator

The adjusting device to vary the amount of air pressure entering as to the amount to be discharged down the piping lines.

Ambient Temperature

The temperature of all the encompassing atmosphere within a given area.

Ampere

The unit used for measuring the quantity of an electric current flow. One ampere represents a flow of one coulomb per second.

Annular Preventer

A device which can seal around any object in the wellbore or upon itself. Compression of a reinforced elastomer packing element by hydraulic pressure effects the seal.

Annular Regulator

The device located in the annular manifold header to enable adjustment of pressure levels which will flow past to control the amount of closure of the annular preventer.


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Annulus

The annular space between two tubulars (i.e. tubing or drill string and the production casing).

Annulus Friction Pressure

Circulating pressure loss inherent in annulus between the drill string and casing or open hole.

Back Pressure (Casing, Choke Pressure)

The pressure existing at the surface on the casing side of the drill pipe/annulus flow system.

Bleeding

Controlled release of fluids from a closed and pressurised system in order to reduce the pressure.

Blind Rams (Blank, Master)

Rams whose ends are not intended to seal against any drill pipe, tubing or casing. They seal against each other to effectively close the hole.

Blind/Shear Rams

Blind rams with a built-in cutting edge that will shear tubulars that may be in the hole, thus allowing the blind rams to seal the hole. Used primarily in subsea systems.

Blowout

An uncontrolled flow of gas, oil, or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid.

Blowout Preventer

The equipment installed at the wellhead to prevent damage at the surface while restoring primary well control. The BOP allows the well to be sealed to confine the well fluids and prevent the escape of pressure.

Blowout Preventer Drill

A training procedure to determine that rig crews are completely familiar with correct operating practices to be followed in the use of blowout prevention equipment. A dry run of blowout preventive action.

Blowout Preventer Operating Control System

Blowout Preventer Stack

B-2

The assembly of pumps, valves, lines, accumulators and other items necessary to open and close the blowout preventer equipment. The assembly of well control equipment including preventers, spools, valves and nipples connected to the top of the wellhead or Xmas tree. © Aberdeen Drilling Schools 2001

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Blowout Preventer Test Tool

A tool to allow pressure testing of drilling or workover blowout preventer stacks and accessory equipment by sealing the wellbore immediately below the stack.

Bleed Off Valve

An opening and closing device for removal of pressurised fluid.

Bottomhole Pressure

Depending upon context, either a pressure exerted by a column of fluid contained in the wellbore or the formation pressure at the depth of interest.

Bullheading

A term to denote pumping well fluids back into a formation in a well kill operation.

Casing Head/Spool

The part of the wellhead to which drilling or workover blowout preventer stack is connected.

Casing Pressure

See Back Pressure.

Casing Seat Test

A procedure whereby the formation immediately below the casing shoe is subjected to a pressure equal to the pressure expected to be exerted later by a higher drilling fluid density or by the sum of a higher drilling fluid density and back pressure created by a kick.

Check Valve

A valve that permits flow in only one direction.

Choke

A diameter orifice (fixed or variable) installed in a line through which high pressure well fluids can be restricted or released at a controlled rate.

Circuit Breaker

An electrical switching device able to carry an electrical current and automatically break the current to interrupt the electrical circuit if adverse conditions such as shorts or overloads occur.

Circulating Head

A device attached to the top of drill pipe or tubing to allow pumping into the well without use of the Kelly.

Clamp Connection

A pressure sealing device used to join two items without using conventional bolted flange joints. The two items to be sealed are prepared with clamp hubs. These hubs are held together by a clamp containing two to four bolts.


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Closing Unit

The assembly of pumps, valves, lines, accumulators and other items necessary to open and close the blowout preventer equipment.

Closing Ratio

The ratio of the wellhead pressure to the pressure required to close the blowout preventer.

Control Panel, Remote

A panel containing a series of controls that will operate the valves on the control manifold from a remote point.

Corrosion Inhibitor

Any substance which slows or prevents the chemical reactions of corrosion.

Cut Fluid

Well control fluid which has been reduced in density or unit weight as a result of entrainment of less dense formation fluids or air.

Cylinder

A device which converts fluid or air power into linear mechanical force and motion. It consists of a movable element such as a piston and piston rod, plunger rod, plunger or ram, operating within a cylindrical chamber.

Degasser

A vessel which utilises pressure reduction and/or inertia to separate entrained gases from the liquid phases.

Discharge Check Valve

The device located in the expelling line of a pump (air or electric) which allows fluid to flow out only and thereby prevents a back flow of fluid into the pump.

Displacement

The volume of steel in the tubulars and devices inserted and/or withdrawn from the wellbore.

Drilling Spool

A connection component with ends either flanged or hubbed. It must have an internal diameter at least equal to the bore of the blowout preventer and can have smaller side outlets for connecting auxiliary lines.


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Drill Stem Test (DST)

A test conducted to determine production flow rate and/or formation pressure prior to completing the well.

Element (Filter)

The substance of porous nature which retains foreign particles that pass through the containing chamber to separate and clean the gas or liquid flow.

Equivalent Circulating Density (ECD)

The sum of pressure exerted by hydrostatic head of fluid, drilled solids, and friction pressure losses in the annulus divided by depth of interest and by 0.052, if ECD is to be expressed in pounds per gallon (lbs/gal).

Feed-in (Influx, Inflow)

The flow of fluids from the formation into the wellbore.

Filter

A device whose function is the retention of insoluble contaminants from a fluid.

Final Circulating Pressure

The pressure required to circulate at the selected kill rate adjusted for increase in kill fluid density over the original fluid density; used from the time kill fluid reaches the circulating point until kill operations are completed or a change in either kill fluid density, or kill rate, is effected.

Flow Meter

A device which indicates either flow rate, total flow, or a combination of both, that travels through a conductor such as pipe or tubing.

Flow Rate

The volume, mass, or weight of a fluid passing through any conductor, such as pipe or tubing, per unit of time.

Flow Target

A bull plug or blind flange at the end of a T to prevent erosion at a point where change in flow direction occurs.

Fluid

A substance that flows and yields to any force tending to change its shape. Liquids and gases are fluids.

Fluid Density

The unit weight of fluid; e.g., pounds per gallon (lbs/gal).


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Fluid Weight Recorder

An instrument in the fluid system which continuously measures fluid density.

Formation Breakdown

An event occurring when bottomhole pressure is of sufficient magnitude that the formation accepts fluid from the hole.

Formation Competency (Formation Integrity)

The ability of the formation to withstand applied pressure.

Formation Competency Test

B-6

(Formation Integrity Test)

Application of pressure by superimposing a surface pressure on a fluid column in order to determine ability of a subsurface zone to withstand a certain hydrostatic pressure.

Formation Integrity

See Formation Competency.

Formation Integrity Test

See Formation Competency Test.

Formation Pressure (Pore Pressure)

Pressure exerted by fluids within the pores of the formation (See Pore Pressure).

Flowline Sensor

A device to monitor rate of fluid flow from the annulus.

Fracture Gradient

The pressure gradient (psi/ft) at which the formation accepts whole fluid from the wellbore.

Function

The term given to the duty of operating a control device.

Gas Buster

A slang term to denote a mud gas separator.

Gate Valve

A valve which employs a sliding gate to open or close the flow passage. The valve may or may not be full-opening.

Gauge

An instrument for measuring fluid pressure that usually registers the difference between atmospheric pressure and the pressure of the fluid by indicating the effect of such pressure on a measuring element (as a column of liquid, a bourdon tube, a weighted piston, a diaphragm, or other pressure-sensitive devices).


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Gland

The metal item which energises stuffing box packing from force applied manually or hydraulically.

Ground

An electrical term meaning to connect to the earth, or another large conducting body to serve as earth, thus making a complete electrical circuit. The conducting connection of a circuit to the earth.

H2S

An abbreviation for hydrogen sulphide.

Hard Close In

To close in a well by closing a blowout preventer with the choke and/or choke line valve closed.

Hydrostatic

Relating to the pressure fluids exert due to their weight.

Hydrostatic Head

The true vertical length of fluid column, normally in feet.

Hydrostatic Pressure

The pressure which exists at any point in the wellbore due to the weight of the vertical column of fluid above that point.

Inflow

See Feed-in.

Influx

See Feed-in.

Initial Circulating Pressure

Pressure required to circulate initially at the selected kill rate while holding back pressure at the closed-in value; numerically equal to kill rate circulating pressure plus closed-in pressure.

Inside Blowout Preventer

A device that can be installed in the drill string that acts as a check valve allowing drilling fluid to be circulated down the string but prevents back flow.

Inspection Port

The plugged openings on the sides of the fluid reservoir of a device which can be opened to view the interior fluid level and return lines from the relief, bleeder, control valves, and regulators.

Kick

Intrusion of formation fluids into a wellbore containing kill or drilling fluid.


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Kill Fluid Density

The unit weight e.g. pounds per gallon (lbs/gal), selected for the fluid to be used to contain formation pressure.

Kill Line

A high-pressure fluid line connecting the mud pump and the wellhead.This line allows fluids to be pumped into the well or annulus with the blowout preventer closed to control a threatened blowout.

Kill Rate

A predetermined fluid circulating rate, expressed in fluid volume per unit time, which is to be used to kill the well.

Kill Rate Circulating Pressure

Pump pressure required to circulate kill rate volume.

Leak-off Test

Application of pressure by superimposing a surface pressure on a fluid column in order to determine the pressure at which the exposed formation accepts whole fluid.

Lost Circulation (Lost Returns)

The loss of whole well control fluid to the wellbore. Lost Returns See Lost Circulation.

Lubrication

Alternately pumping a relatively small volume of fluid into a closed wellbore system and waiting for the fluid to fall toward the bottom of the well.

Lubricator

The pressure containing tubulars mounted above the Xmas tree for installing wireline or coiled tubing toolstrings in live wellbores.

Manifold Header

The piping system which serves to divide a flow through several possible outlets.

Meter

An instrument, operated by an electrical signal, that indicates a measurement of pressure.

Micron

A millionth of a metre or about 0.0004 inch. The measuring unit of the porosity of filter elements.

Minimum Internal Yield Pressure The lowest pressure at which permanent deformation will occur in metals. Mud-gas Separator

B-8

A vessel for removing free gas from the drilling/kill fluid returns.


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Needle Valve

A shut-off two way valve that incorporates a needle point to allow fine adjustments in flow.

Normal Pressure

Formation pressure equal to the pressure exerted by a vertical column of water with salinity normal for the geographic area.

Opening Ratio

The ration of the well pressure to the pressure required to open the blowout preventer.

Overbalance

The amount by which pressure exerted by the hydrostatic head of fluid in the wellbore exceeds formation pressure.

Overburden

The pressure on a formation due to the weight of the earth material above that formation. For practical purposes this pressure can be estimated at 1 psi/ft of depth.

Packing

Rubber elements used in wireline stuffing boxes to seal around slick wirelines.

Packoff or Stripper

A device with an elastomer packing element that depends on pressure below the packing to effect a seal in the annulus. Used primarily to run or pull pipe under low or moderate pressures. This device is not dependable for service under high differential pressures.

Pipe Rams

Rams whose ends are contoured to seal around pipe to close the annular space. Separate rams are necessary for each size (outside diameter) pipe in use.

Pit Volume Indicator

A device installed in the drilling fluid tank to register the fluid level in the tank.

Pit Volume Totaliser

A device that combines all of the individual pit volume indicators and registers the total fluid volume in the various tanks.

Plug Valve

A valve whose mechanism consists of a plug with a hole through it on the same axis as the direction of fluid flow. Turning the plug 180 degrees opens or closes the valve.The valve may or may not be fullopening. Pressure exerted by the fluids within the pore space of a formation.

Pore Pressure © Aberdeen Drilling Schools 2001

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Potable

A liquid that is suitable for drinking.

Pressure Gradient, Normal

The normal pressure divided by true vertical depth.

Pressure Integrity Test (PIT)

Application of pressure by superimposing a surface pressure on a fluid column in order to determine the pressure at which the well can withstand before a well intervention. This test is less than formation fracture pressure to prevent formation damage.

Pressure Transmitter

Device which sends a pressure signal to be converted and calibrated to register the equal pressure reading on a gauge. The air output pressure in proportion to the hydraulic input pressure.

Primary Well Control

The primary well control system or device on the well.

Pump (Air)

A device that increases the pressure of a fluid or raises it to a higher level by being compressed in a chamber by a piston operated with an air pressure motor.

Pump (Electric)

A device that increases the pressure of a fluid and moves it to a higher level using compression force from a chamber and piston that is driven by an electric motor.

Push-button/Indicating Light

The control valve operates with bulbs on the electrical remote panel which change and indicate the position of the control valves.

Ram

The closing and sealing component on a blowout preventer. One of three types - blind, pipe, or shear - may be installed in several preventers, mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drillpipe and then form a seal.

Recorder

An device that records outputs of pressure, temperature continually on a chart to provide continuous reading.


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Regulator

A device that varies and controls the amount of pressure of a liquid or gas that passes through its chambers.

Replacement

The process whereby a volume of fluid equal to the volume of steel in tubulars and tools withdrawn from the wellbore is returned to the wellbore.

Reservoir

The container for storage of a liquid. The reservoir houses hydraulic fluid at atmospheric pressure as the supply for fluid power.

Rupture Disc

A device whose breaking strength (the point at which it physically bursts) works to relieve pressure in a system.

Safety Factor

A margin added to a figure or value purely for safety.

Shear Rams

Blowout preventer rams with a built in cutting edge that will shear tubulars that may be in the hole.

Snubbing

The process of installing pipe into a well where the well pressure is greater than that of the weight of pipe in the hole. It has also come to mean any of the live well interventions carried out by a hydraulic workover unit.

Soft Close In

To close in a well by closing a blowout preventer with the choke and choke line valve open, then closing the choke while monitoring the casing pressure gauge for maximum allowable casing pressure.

Sour Gas

Natural gas containing hydrogen sulphide.

Space Out

Procedure conducted to position a predetermined length of tubing/drill pipe so that no connection or tool joint is opposite a set of preventer rams.

Space-Out Joint

The joint of tubing/drill pipe which is used to hang off operations so that no tool joint is opposite a set of preventer rams.


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Squeezing

Pumping fluid into a formation.

Stack

The assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the casing head.

Stripper

See Pack-Off.

Stripping

The process of running pipe through a stripper with or without pressure in the well.

Swabbing

The lowering of the hydrostatic pressure in the wellbore due to upward movement of tubulars and/ or tools.

Transducer

The device located in the solenoid valve box which is actuated by hydraulic pressure and converts the force to an electrical signal for indication on a meter. The electrical output signal is in proportion to the hydraulic input pressure.

Tubing Safety Valve

An essentially full-opening valve located on the rig floor with threads to match the tubing in use. This valve is used to close off the tubing to prevent flow.

Tubulars

Drill pipe, drill collars, tubing, and casing.

Underground Blowout

An uncontrolled flow of formation fluids from a sub-surface zone into a second subsurface zone.

Underbalance

The amount by which formation pressure exceeds pressure exerted by the hydrostatic head of fluid in the wellbore.

Valve, Float

A device that is positioned as either open or closed, depending on the position of a lever connected to a buoyant material sitting in the fluid to be monitored.

Valve, Poppet

The opening and closing device in a line of flow which restricts flow by lowering a piston type plunger into the valve passageway.

Valve, Relief

A valve that opens at a present pressure to relieve excessive pressures within a vessel or line whose primary function is to limit system pressure. © Aberdeen Drilling Schools 2001

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Valve, Shut-off

A valve which operates fully open or fully closed to control the flow through a conduit.

Valve, Sub-Surface Safety

A completion safety valve installed at a depth below the surface according to various criteria. A measure of the internal friction or the resistance of a fluid to flow.

Viscosity

Watt

A unit of electromotive force.

Weight Cut

The amount by which a drill or kill fluid density is reduced by entrained formation fluids or air.

Wireline BOP (valve)

Preventers installed on top of the well or drill string as a precautionary measure while running wirelines. The preventer packing will close around the wireline.

Xmas Tree

The head terminating a completion with a set of valves to control well flow and well servicing activities.


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PREVENTERS

C.1

ANNULAR PREVENTERS

C.2

RAM PREVENTERS

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C. APPENDIX - PREVENTERS C.1 ANNULAR PREVENTERS C.1.1 Introduction The annular preventer consists of a flexible reinforced element that can seal any size tubular. The element is squeezed round the tubular by a piston of relatively large area. Because of this, the operating pressure is relatively low (usually regulated between 0 and 1,500 psi as needed) and so pipe can be stripped into the hole under pressure if necessary. Table C.1 shows some recommended closing pressures. If upset pipe has to be stripped through an annular, the rubber is forced out whenever a tool joint passes through it.This in turn forces fluid from the closing side of the piston and so surge chambers are needed to handle this flow. (See Figure C.1) shows a Hydril GK (surface type) preventer. The majority of annular preventers currently in use are manufactured by Hydril (Types MSP, GK, GL, GX), Shaffer (Spherical) and Cameron (Type D), these are illustrated (See Figure C.1, Figure C.2, Figure C.3 together with a summary of major operating features. The following are the most important aspects of the operation of annular preventers: • To obtain maximum sealing life, hydraulic closing pressures should conform to the manufacturer’s recommendations for pressure testing and operational use of the preventers. Excessive closing pressures, when coupled with wellbore pressure sealing effects, cause high internal stresses in the element and reduce element life. • Cavities should be flushed out and the element inspected following each well. Preventers should be stripped and inspected annually. Seals should be replaced and all sealing surfaces inspected. • Cap seals should be replaced when changing elements. • Tooling, especially mills and bits, should be run cautiously through BOPs to minimise element damage. Elements of annular preventers do not, on occasions, retract fully. • The type of elastomer (natural rubber, synthetic rubber, neoprene) used in the packing element should be the most suitable for a particular wellhead environment; Figure C.1 and Figure C.2 • Although most models and sizes of annular preventer will seal an open hole in an emergency operation, it is not recommended, as such gross deformation of the elastomer causes cracking and accelerated wear. • Closing pressures should be regulated to the pressures specified by the manufacturers.This information should be available at the rigsite. When stripping, the closing pressure should be regulated to the minimum required for a slight weeping of well fluid past the element. Closing pressures higher than this will increase element wear. The pipe should be moved slowly, particularly as tool joints pass through the element.The manufacturers also provide information regarding recommended closing pressures during stripping operations. Surge vessels on the closing ports will help to smooth-out surge pressures as tool joints pass through the element. © Aberdeen Drilling Schools 2001

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C.1.2 Hydril ‘Gk’ Annular Preventer a) 41/16" 10,000, 15,000 and 20,000 psi WP Operating Features: 1. 2. 3. 4. 5. 6. 7. 8.

Designed for stripping and snubbing operations. The packing unit and the operating chambers are tested to rated working pressure. The BOP body is tested to 11/2 times the rated working pressure. Will close on open hole. Has provision to measure piston travel to gauge element wear. Is available with bolted top. Sealing assistance is gained from the well pressure. Meets the current (Revision of NACE) Standards for sulphide stress cracking.

Figure C.1- Hydril Annular Preventer - ‘GK’ 41/16" 10,000 15,000 & 20,000 psi WP

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b) 71/16" 15,000 psi WP Operating Features: 1. 2. 3. 4. 5.

Will close on open hole. Sealing assistance is gained from the well pressure. Meets the current revision of NACE Standards for sulphide stress cracking. The head has a field replaceable wear plate which is bolted on. Has provision to measure piston travel to gauge element wear.

If the annular packing element wears out during stripping or well killing operations, the element can be changed without having to pull the pipe. After the pipe rams are closed and locked below the annular preventer and both the hydraulic and well pressure below is bled off, the cover of the preventer can be unbolted and the packing element lifted out with a tugger or hoist line.With the element above the preventer, the damaged unit can be split and removed from the pipe. A new element would be installed in reverse sequence of the above.

Figure C.2- Hydril Annular Preventer - ‘GK’ 71/6" 15,000 psi WP


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C.1.3 Hydril ‘Gl’ Annular Preventer Ring Groove Wear Plate Latched Head

Seals

Packing Unit Hydraulic Connection

Seals

Piston Bowl

Seals Seals

Piston Hydraulic Connection Seal Hydraulic Connection

Seals

Ring Groove

Figure C.3- Hydril Annular Preventer - Type ‘GL’

Operating Features: 1. Will close on open hole (but not recommended). 2. Some sealing assistance is gained from well pressure. 3. Bolted cover for easier element charge. 4. Primarily designed for subsea operations. 5. Has a provision to measure piston travel to gauge element wear. 6. Has a balancing chamber to offset hydrostatic pressure effect in subsea operations. The chamber can be connected four ways to optimise operations for different effects: • Minimise closing/opening fluid volumes. • Reduce closing pressure and times. • Automatically compensate (counterbalance) for marine riser hydrostatic pressure effects in deep water. • Operate as a secondary closing chamber.

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Standard Surface Hook-up Requires Least Fluid So Gives A Faster Closing Secondary Chamber Connected To Opening Chamber (S - O)

Subsea Hook-up For Water Depths Over 800 Ft. Secondary Chamber Connected To Closing Chamber (S - C)

Subsea Hook-up For Water Depths Up To 800 Ft. Secondary Chamber Connected To Marine Riser (CB)

OPENING PRESSURE

CLOSING PRESSURE

Figure C.4- Hydrill ‘GL’ Annular Preventer Operation


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C.1.4 Cameron Annular Preventers

PACKING UNIT

OPENING CHAMBER PISTON CLOSING CHAMBER

Figure C.5- Cameron 20,000 psi WP Annular Blowout Preventer

Operating Features: 1. Will close on open hole. 2.Vents isolate the hydraulic operating system from the well pressure. 3. Standard trim suitable for H2S service. 4. Operating chambers remain sealed during packer element change to prevent contamination. 5. The quick-release top latch reduces time to change packing element. 6.The packing element contains steel reinforcing inserts forming a continuous ring that gives maximum support as they close inward.

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Figure C.6- Cameron Annular Preventer - Type ‘D’

Operating Features: 1. Quick-release top latch for easier element change. 2. Most sizes use less closing fluid than Shaffer and Hydril annular preventers. 3. Overall height is less than Hydril and Shaffer annular preventers. 4. Weight of preventer is less than Hydril and Shaffer annular preventer in all sizes except for 11" 10,000 psi WP. •

Cameron’s Type D annular preventer requires 3,000 psi hydraulic closing pressure for positive closure with no pipe in the preventer.This requires a bypass arrangement around the 1,500 psi annular regulator on 3,000 psi closing units.


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OPEN

CLOSED ON PIPE

CLOSED ON OPEN HOLE

Figure C.7- Cameron 20,000 psi WP Annular Blowout Preventer Sealing Element

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C.1.5 Shaffer Annular Preventers

Figure C.8- Shaffer Annular Preventers

Operating Features: 1.

2.

3. 4.

Will close on open hole (but not recommended). As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inward to a sealing engagement with anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape. Requires higher closing pressure in subsea applications.As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inward to a sealing engagement with anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape. Some sealing assistance is gained from the well pressure. No provision for measuring piston travel. Hydril’s and Shaffer’s annular preventers are claimed to provide positive closure with 1,500 psi closing unit pressure when the rubber elements are new.


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Table C.1 - Typical Average Closing Pressure

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C.1.6 Packing Element Selection Only packing elements which are supplied by the manufacturer of the annular preventer should be used. New or repaired units obtained from other service companies should not be used since the preventer manufacturers cannot be held responsible for malfunction of their equipment unless their elements are installed. See Table C.2. PACKING UNIT TYPE

IDENTIFICATION Colour Code

Natural Rubber

Black

Nitrile Rubber

Red

Neoprene Rubber

OPERATING TEMP RANGE

WELL FLUID COMPATIBILITY

-30˚F – 225˚F

Waterbase Fluid

20˚F – 190˚F

Oil base/ Oil Additive Fluid

NR NBR Band

Green Band

CR

-30˚F – 170˚F

Oil Base Fluid

Table C.2 - Packing Unit Selection (from Hydril) SIZE AND WORKING PRESSURE Inches

6 6 7 1/16 8 8 10 10 11 11 12 13 5/8 13 5/8 13 5/8 16 16 16 3/4 16 3/4 16 3/4 18 18 3/4 20 20 20 30 30

psi

3,000 5,000 10,000 3.000 5,000 3,000 5,000 5,000 10,000 3,000 3,000 5,000 10,000 2,000 3,000 3,000 5,000 10,000 2,000 5,000 2,000 3,000 5,000 1,000 2,000

HYDRIL GK

NL SHAFFER SPHERICAL

GL

Close

Open

2.9 3.9 9.4 4.4 6.8 7.5 9.8

Close

Open

Balancing

Close

Open

2.2 3.3

4.6 4.6

3.2 3.2

3.0 5.8 5.6 8.0

7.2 11.1 11.0 18.7

5.0 8.7 6.8 14.6

25.1 11 . 4

9.8

23.5

14.7

18.0 34.5 17.5 21.0

14.2 24.3 12.6 14.8

19.8

19.8

8.2

23.6 47.2

17.4 37.6

28.7

19.9

33.8

33.8

17.3

33.0

25.6

21.1

14.4 44.0

44.0

20.0

48.2 32.6

37.6 17.0

58.0

58.0

29.5

61.4

47.8

Table C.3 - Annular Preventers - Gallons of Fluid Required to Operate on Open Hole © Aberdeen Drilling Schools 2001

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C.2 RAM PREVENTERS It is not possible to detail every type of ram preventer manufactured for all the applications for which they are used including rig, snubbing, coiled tubing and wireline operations. The following are only typical examples of those in use. C.2.1 Cameron The U II blowout preventer provides a BOP system (including CAMRAM elastomer sealing) that meets the API 6A rating of 250˚F service.The U II includes an internally ported hydraulic bonnet stud tensioning system, a short stroke bonnet, bore type bonnet seals, and the proven advantages of the U BOP design. • The introduction of the CAMRAM packer has set a new industry standard in meeting the 250˚F and withstand excursions to 300˚F Presently, the API standard excludes these critical sealing elements from the rating, which covers only the metal components of the BOP system. • CAMRAN packers and top seals made with CAMLAST are available for high temperature and high H2S service. • The bonnets of the U II preventer are opened and closed hydraulically. The bonnet studs are hydraulically stretched to the correct preload by pressure applied behind a piston which acts on a load rod in the stud. The nut is tightened and pressure is released. Pressure is supplied by an air-powered hydraulic pump via internal porting in each end of the BOP body. • The short stroke bonnet reduces the opening stroke by about 30%, reduces the overall length of the preventer, and reduces the weight supported by the ram change pistons. • The bore type bonnet seal fits into a seal counterbore in the body and has metal antiusion rings. • The U II blowout preventer wedgelocks act directly on the operating piston tailrod. The operating system can be interlocked using sequence caps to ensure that the wedgelock is opened before pressure applied to open the preventer. • A ram bearing pad can be attached to the bottom of each ram to reduce ram bore wear. • All Cameron U II BOPs are manufactured to comply with NACE and all regulatory body specifications.

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C.2.2 Double U II

Figure C.9 - Double UII BOP

Operating Features: 1. 2. 3. 4. 5. 6.

Application in both surface and Sub-Sea applications. Well bore assist. Accurate preload and fast make up for ram change. Secondary seals on operating rod. 250˚F of rating for H.P. wells. Automatic locking device (self adjusting).


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Figure C.10 - UII BOP Hydraulic Control System

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C.2.3 ‘SS’ Space Saver

Figure C.11 - Cameron Ram Preventer - Type ‘SS’ (Space Saver)

Operating Features: • • • • •

Low in vertical height. Ram position cannot be determined by external observation. Well pressure assists in maintaining rams closed. Has secondary operating rod seal. Rams can be changed and repaired in the field.


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C.2.4 Shaffer On shaffer type LWS or SL rams, the locking device is actuated automatically whenever the ram is closed. Called the Poslock, this system uses segments that move out radically from the ram piston and lock into a groove in the circumference of the operating cylinder whenever the ram is closed. When hydraulic closing pressure is applied, the complete piston assembly moves inward and pushes the ram towards the wellbore. With the rams closed, the closing pressure then forces a locking piston inside the main piston to move further inwards and force out the segments. A spring holds the locking piston in this position so that the segments are kept locked in the groove even if closing pressure is lost. When hydraulic opening pressure is applied, the locking cone is forced outward. This allows the locking segments to retract back into the main piston which is then free to move outwards and open the ram.

Figure C.12 - Poslock Adjustment

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UltraLock is a versatile locking system. It provides a maintenance-free and adjustment-free locking system that is compatible with any ram assembly that the blowout preventers can accommodate. Once the UltraLock is installed, no further adjustments will be needed when changing between Pipe Rams, Blind/Shear or MULTI-RAM assemblies. BOPs that are equipped with the UltraLock are automatically locked in the closed position each time the BOPs are closed; no preset pressure ranges are needed.The BOPs remain locked in the closed position, even if closing pressure is lost or removed. Hydraulic opening pressure is required to re-open the preventer, and this opening pressure is supplied by the regular opening and closing ports of the preventer. No additional hydraulic lines or functions are required for operations of the locks. Stack frame modifications are not required because all operational components are in the hydraulic operating cylinders. Existing BOPs with PosLock Cylinders can be upgraded to the UltraLock.

Figure C.13 - Ultralock Locking System


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C.2.5 Hydril

Figure C.14 - Hydril Ram Preventer

Operating Features: 1. 2. 3. 4. 5. 6. 7.

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Available with manual or automatic locking systems. Cylinder liner is field replaceable or repairable. Secondary rod sealing action. Rams can be changed and repaired in the field. Additional room must be allowed for side door openings. Sloped ram cavity is self-draining of mud and sand. Rams are designed to permit drill pipe hang-off.


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C.2.6 Ram Types

a) Shaffer Shear Ram Shaffer Shear Rams shear pipe and seal the wellbore in one operation. They also function as Blind or CSO (Complete Shut Off) Rams for normal operation.To ensure adequate shearing force, a minimum of 14" pistons are required when operating Shaffer Shear Rams.The hydraulic closing pressure for normal shearing is 3,000 psi or blind operation at 1,500 psi accumulator pressure.When shearing pipe in a subsea BOP stack, 3,000 psi accumulator pressure is required. When shearing, the lower blade passes below the sharp lower edge of the upper ram block and shears the pipe.The lower section of cut pipe is accommodated in the space between the lower blade and the upper holder. The upper section of cut pipe is accommodated in the recess in the top of the lower ram block. Closing motion of the rams continues until the ram block ends meet. Continued closing of the holder squeezes the semicircular seals upward into the sealing contact with the seat in the BOP body and energises the horizontal seal. The closing motion of the upper holder pushes the horizontal seal forward and downward on top of the lower blade, resulting in a tight sealing contact. The horizontal seal has a moulded-in support plate which holds it in place when the Rams are open. The shaffer Shear Rams are also available for H2S service which meets the requirements of NACE Standard MR-01-75. Shaffer Shear Rams are covered by U.S. Patent No. 3,736,982.

Figure C.15 - Shaffer Shear Rams


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C.2.7 Variable Rams

Figure C.16 - Variable Rams 5" - 27/8"

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WP (psi)

Open

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71/16

3,000 5,000 10,000 15,000

2.3 2.3 2.3 2.3

6.9 6.9 6.9 6.9

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HYDRIL RAM Open

Close

1.5 1.5 1.7 6.6

5.4 5.4 8.2 7.6

2.6 2.6

5.3 5.3

6.8 6.8 7.6 7.6

7.11

2,000 3,000 5,000 10,000 2,000 3,000 5,000 10,000 15,000

2.5 2.5 2.5 2.5 2.2

7.3 7.3 7.3 7.3 9.9

7.62 2.8

7.11 7.11

2.0 2.0 2.4 3.24

135/8

3,000 5,000 10,000 15,000

2.3 2.3 2.3 5.6

7.0 7.0 7.0 8.4

3.00 3.00 4.29 2.14

5.54 5.54 7.11 7.11

2.1 2.1 3.8 3.56

5.2 5.2 10.6 7.74

163/4

2,000 3,000 5,000 10,000

2.3 2.3 2.3

6.8 6.8 6.8

2.03 2.06

5.54 7.11

2.41

10.6

183/4

10,000 15,000

3.6 4.1

7.4 9.7

1.83 1.68

7.11 10.85

1.9 2.15

10.6 7.27

211/4

2,000 3,000 5,000 10,000

1.3 1.3 5.1 4.1

7.0 7.0 6.2 7.2

0.98 0.98 1.9

5.2 5.2 10.6

2,000 3,000

1.0

7.0

11

263/4

1.63

7.11

Table C.4 - Ram Preventer Opening and Close Ratios


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Example Closing forces in relation to area: 1. When closing the well, the string is picked up say 20 ft off bottom. The annular preventer is then closed and the fail-safes opened against a closed choke. 2. The tool joint is then spaced out for the correct pipe rams. 3. The string is stripped down until the tool joint is “hung off ” on the rams. The correct operating pressure to set on the manifold regulator is directly related to the well bore pressure. For example: Operating ratio 10:56:1. Working pressure of BOP stack 10,000 psi. This pressure does not include an allowance for friction losses so the minimum pressure would be say 1000 psi : 1000 psi x 10.56 = 10560 lbs closing force.

RAM Shaft Area

Closing Pressure

Figure C.18 - Closing Forces in Relation to Area

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Table C.5 - Ram Preventers - Fluid Required to Operate


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CHOKES

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D. APPENDIX - CHOKES D.1 HP PRODUCTION CHOKES K Choke Beans and Wrenches: • Flared Orifice entrance reduces erosion on the entrance surface. • Accuracy levels are maintained over extended periods of use. • Choke beans save time and money because replacement intervals are extended. Cameron K choke beans come in two styles, positive and combination.The positive bean has a fixed orifice diameter. The combination bean has a fixed diameter and a throttling taper at the entry.The combination bean is used with an adjustable choke needle to make incremental changes to orifice sizes smaller than the fixed orifice. The part numbers of the positive and combination beans are determined by desired orifice size. K1 positive bean orifice sizes range from 4/64" to 64/64". K2 positive bean orifice sizes range from 4/64" to 128/64". K3 positive bean orifice sizes range from 4/64" to 192/64". K1 combination bean sizes range from 6/64" to 64/64". K2 combination bean sizes range form 6 /64" to 128/64". K3 combination bean sizes range from 6/64" to 192/64".


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Figure D.1 - Cameron Fixed Bean Choke System

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Figure D.2 - HP Production Chokes


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Figure D.3 - ‘K3’ Choke

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APPENDIX E

E.

WIRELINE SURFACE PRESSURE CONTROL EQUIPMENT

E.1

INTRODUCTION

E.2

WELLHEAD PRESSURE CONTROL EQUIPMENT

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E. APPENDIX- WIRELINE SURFACE PRESSURE CONTROL EQUIPMENT E.1 INTRODUCTION Wells in which Wireline Services are performed may contain a wide range of wellhead pressures (WHP), for example from a few psi. up to several thousand psi.This pressure is normally due to the natural pressure of the producing formation into which the well has been drilled. Working in a pressurised well allows remedial or investigative work to be performed without ‘killing’ the well. Although killing the well is safer, it is a costly, time consuming exercise requiring a rig and perhaps damaging the producing formation in the process. Current Wellhead Pressure Equipment and practices allows a wire to be run in and out of the well.Various wireline tools can be run and retrieved with a high degree of safety. Despite this, wireline operations with pressure in the well require highly-qualified personnel and rigorous operating and safety procedures since the safety/control of the well is under their management.

E.2 WELLHEAD PRESSURE CONTROL EQUIPMENT To enable the tools to be run into the well under pressure, the surface equipment shown below is required. Each component on the following list is discussed in the next sections. • Quick Unions • Wellhead Adapter • Pump-in Tee • Wireline Valve (BOP) • Lubricator - Bleed Off Valve • Safety Check Union • Stuffing Box • Hydraulic Packing Nut • Grease Injection Head • Flow Tubes • Grease Injection System • Hay Pulley • Weight Indicator • Wireline Counter • Wireline Clamps. The relative positions of some of these components are shown in Figure E.1


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Figure E.1 - Example of a Wireline Rig Up E.2.1 Quick Unions

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The connections used to assemble the Lubricator and related equipment are referred to as Quick Unions; See Figure E.2.They are designed to be quickly and easily connected by hand. The box end receives the pin end which carries an O-ring seal. The collar has an internal Acme thread to match the external thread on the box end. This thread makes up quickly by hand and should be kept clean.The O-ring forms the seal to contain the pressure and should be thoroughly inspected for damage and replaced if necessary. A light film of oil or grease helps in the make up of the union and prevents cutting of the O-ring. Pipe wrenches, chain tongs or hammers should never be used to loosen the collar of the union. If it cannot be turned by hand, all precautions must be taken to make sure that the well pressure has been completely released. CAUTION: IN GENERAL, UNIONS THAT CANNOT BE LOOSENED EASILY INDICATE THAT HIGH PRESSURE MAY BE TRAPPED INSIDE. IF THIS PRESSURE IS NOT BLED OFF FIRST, UNSCREWING THE UNION COULD CAUSE A SUDDEN RELEASE OF PRESSURE, PROJECTING EQUIPMENT PARTS AT LETHAL SPEEDS. The collar of the union will make up by hand when the pin end (with the O-ring) has been shouldered against the box end. When the collar bottoms out, it should be backed off approximately one quarter turn to eliminate any possibility of it sticking due to friction when the time comes to disconnect it. Rocking the lubricator to ensure it is perfectly straight will assist in loosening the quick union. In addition, ensure that tugger lines and hoists are properly placed to lift the lubricator assembly directly over the wellhead.

Figure E.2 -Quick Union © Aberdeen Drilling Schools 2001

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E.2.2 Wellhead Adapter (Tree Adapter) All Wellhead Adapters are crossovers from the Xmas tree to the bottom connection of the WirelineValve or Riser. It is important to check that the correct type of threads with appropriate pressure ratings are used on the top and bottom of the adapter. Three types of Wellhead Adapter, See Figure E.3, are in common use: • Quick Union to Quick Union • API Flange to Quick Union • Acme Thread to Quick Union.

Figure E.3 - Wellhead Adapters E.2.3 Pump-in Tee

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A Pump-In Tee; See Figure E.4, consists of three main parts: • A Quick Union box end • A Quick Union pin end • A Chiksan/Weco type connection. The Pump-in Tee, when rigged up, is placed between the Wellhead adapter and the wireline BOP. Therefore, Quick Union sizes and pressure ratings must be compatible with all surface equipment. Pump-in Tees may be required as part of a wireline rig-up. By connecting a kill-line to the Chiksan/Weco connection, the well can be killed in an emergency situation. This line can also be used to pressure test or release pressure from the surface equipment. NOTE: On some locations, the pump-in tee will be part of the wellhead adapter.

Figure E.4 - Pump-in Tee


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E.2.4 Wireline Valve (BOP) a) Description A Wireline Valve; See Figure E.5, must always be installed between the Wellhead/ Xmas tree and Wireline Lubricator. This valve is a piece of safety equipment that can close around the wireline and seal off the well below it. This enables the pressure to be bled off above it, allowing work or repairs to be carried out on equipment above the valve without pulling the wireline tools to surface. A positive seal is accomplished by means of rams which are manually or hydraulically closed without causing damage to the wire. Hydraulically actuated Wireline Valves are more commonly used because of the speed of closing action and ease of operation. During an emergency, often the valve is not easily accessible to allow fast manual operation and therefore remote actuation is preferred. Single or dual ram valves are available in various sizes and in a full range of working pressure ratings. Dual rams offer increased safety during slick line work and allow the injection of grease to secure a seal on braided wireline. They are used particularly in gas wells, or wells with a gas cap. Wireline Valves are fitted with equalising valves that allow Lubricator and well pressure to equalise prior to opening the rams when wireline operations are to be resumed.Without this, if the valve rams were to be opened without first equalising, the pressure surge could blow the toolstring or wire into the top of the Lubricator, causing damage or breakage. WARNING: SINCE THEY ARE SUCH A VITAL COMPONENT CONTROLLING THE SAFETY OF THE WELL, IT IS IMPORTANT THAT WIRELINE VALVES ARE REGULARLY PRESSURE AND FUNCTION TESTED. TESTS SHOULD BE CARRIED OUT PRIOR TO TRANSPORT OFFSHORE, BEFORE EACH NEW WIRELINE OPERATION AND AFTER ANY REDRESS OR REPAIR OF THE VALVE. b) Uses of Wireline Valves • To enable well pressure to be isolated from the lubricator when leaks develop etc. without cutting wire by closing the master valve. • To permit assembly of a wireline cutter above the rams. • To permit dropping of wireline cutter or cutter bar. • To permit ‘stripping’ of wire through closed rams only when absolutely necessary. A mechanical or hydraulic force is applied to close the rams to seal against well pressure. The sealing elements are arranged so that the differential pressure across them forces them closed and upwards, assisting in the sealing action. Figure E.6 shows the ram configuration of a Wireline Valve. Blind rams close without wire and will also close on 0.108 in. wire without damage. Both 3/16 in. and 7/32 in. rams have a semi circular groove in each of the two ram faces to permit the ram to close and seal on 3/16 in. or 7/32 in. braided line. E-6


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Figure E.5- Typical Wireline Valve (BOP)


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Figure E.6 - Wireline Valve Ram Configuration

NOTE: Ensure that the correct guide is installed as an incorrect guide may damage or cut the wire. CAUTION: WIRELINE VALVES WILL HOLD PRESSURE FROM BELOW ONLY. d) Equalising Valves Permits equalisation of pressure from below the closed rams, after bleed off of the lubricator. The equalising valve must be opened and closed prior to use. A check should be made to ensure that the equalising assembly is not inverted and that the retainer screw is towards the bottom of the valve; See Figure E.5. When operating with stranded/braided line, it is strongly recommended that a twin valve or two single valves (one on top of the other), be installed and equipped with the appropriate size moulded rams with the lower rams inverted to shut off from above. This enables grease injection between the rams to block off the interstices of the braided line, preventing leakage through the internal parts of the wire. NOTE: If the BOP fails test, the equalising valve should be checked to confirm it is fully closed.

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E.2.5 Lubricators - Bleed Off Valve The Lubricator is, in effect, a pressure vessel situated above the Xmas Tree, subject to the wellhead shut-in pressure and also test pressures. For this reason, it should be regularly inspected and tested in accordance with Statutory Regulations. All Lubricator sections and accessories subject to pressure must be stainless steel banded; the band should be appropriately stamped with the following data:- maximum working pressure, test pressure, and date and rating of last hydrostatic test. a) Description A Lubricator allows wireline tools to enter or be removed from the well under pressure. It is a tube of selected ID. and can be connected with other sections to the desired length by means of Quick Unions; See Figure E.7. The following factors govern the selection of Lubricators: • Shut-in wellhead pressure • Well fluid • Wireline tool diameter • Length of wireline tools. The lowermost Lubricator section normally has one or more bleed off valves installed; a pressure gauge can be connected to one of the valves to monitor pressure in the Lubricator. If the Lubricator has no facility to install valves then a Bleed-off Sub, a short Lubricator section with two valves fitted, should be connected between the Wireline Valve and Lubricator. Quick Unions connect Lubricator sections together and to the Wireline Valve; these unions have Acme type threads and seal by means of an O-ring, thereby requiring only tightening by hand; See Figure E.8. b) Construction Lubricators for normal service (up to 5,000 psi.) can be made of carbon or manganese steel. Over 5,000 psi., consideration should be given to sour service as quantities of H2S can be absorbed into the steel of the Lubricator body and heat treatment becomes necessary. All Lubricator sections must have full certification from the manufacturer or test house. A standard colour code identifies different pressure ratings of lubricator.


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Figure E.8 - Lubricator Connectors

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A colour coding system is usually implemented. The colour coding system uses one or two bands of colour to identify the service. For example in the Shell Expro system, the pressure rating is identified by the base colour of the item (e.g. lubricator) or accessory and should satisfy the following:

MAXIMUM WORKING PRESSURE (psi)

COLOUR

3,000

Red

5,000

Dark Green

10,000

White

15,000

Yellow

Table E.1 - Colour Coding and Pressure Rating of Pressure Control Equipment

The first band indicates if the service is Standard or Sour. Standard service has no band. Sour service has an orange band. The second band indicates the temperature of the service. Standard service (-30˚C to 250˚C) has no band. Low temperature service (below -30˚C) has a blue band. High temperature service (above 25˚C) has a purple band.


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E.2.6 Stuffing Box The Stuffing Box; See Figure E.9, is a sealing device connected to the top of the Lubricator sections and in conjunction with the lubricator is the primary pressure control on the well. It allows the wireline to enter the well under pressure and also provides a seal should the wireline break and be blown out of the packing. The Stuffing Box will cater for all sizes of slickline but the size of the wire must be specified to ensure the correct packing rubbers are installed. If the wireline breaks in the well, the loss of weight on the wire at surface allows well pressure to eject the wire from the well.To prevent well fluids leaking out the hole left by the wire, an Internal Blow Out Preventer Plunger is forced up into the Stuffing Box by well pressure and seals against the lower gland. A packing nut and gland located at the top of the Stuffing Box can be adjusted to compress the packing and seal on the wireline. Hydraulically controlled Packing Nuts are available to ease operation should the packing require to be compressed during wireline operations.These are controlled remotely by a hand pump and this avoids the need for manual adjustment of the Packing Nut. For slickline operations, the top sheave is normally an integral part of the Stuffing Box. This reduces the rig up equipment required and the large 10 or 16 ins. sheaves can handle the larger OD. wire with less fatigue and breakdown . Wireline sealing devices fulfil one of two functions: • Pressure containment (sealing) • High pressure containment on braided line. For solid wirelines, only pressure containing Stuffing Boxes are utilised.The standard Stuffing Box is available in 5,000 psi. and 10,000 psi. pressure ratings although higher pressure ratings are now also available. The essential function of the Wireline Stuffing Box is to ensure containment or sealing off around solid wirelines, whether stationary or in motion, at the upper end of the Lubricator during wireline operations. In addition, most Stuffing Boxes contain a BOP plunger which is forced out of the packing section to seal off flow in the event of wireline breakage. A swivel-mounted (360˚ free movement) sheave wheel and guard are fitted to the top half of the Stuffing Box. The wheel is positioned so as to maintain the passage of the wire through the centre of the packing rubbers. The sheave guard on the Stuffing Box is designed to trap any wire which breaks on the surface before it drops downhole. The adjustment to the packing retainer nut at the top of the Lubricator is time consuming and a Hydraulic Packing Nut; See Section E2. E.2.7, can be installed so that control can be executed from the deck. E-12


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Figure E.9 - Wireline Stuffing Box


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E.2.7 Hydraulic Packing Nut The Hydraulic Packing Nut assembly, See Figure E.10, is designed for a standard Wireline Stuffing Box to allow remote adjustment of the packing nut.This method is a safe and convenient way of regulating the packing nut. Regulation is made from a ground position by means of a hydraulic hand pump and hose assembly. a) Benefits The need for a person to climb the lubricator is eliminated. The hand pump is positioned away from the nut itself, and therefore possible escaping well fluid. b) Operation The Hydraulic Packing Nut Assembly includes a piston which has a permissible travel of 0.4 in. enclosed in a housing. The housing has a 1/4" NPT connection for a hydraulic hose. The area above the piston is arranged so that when hydraulic pressure is applied to this area, the piston is forced downward against the force of the spring. This downward action of the piston is transmitted to the upper packing gland. This is designed to cause the Stuffing Box packing to be squeezed around the wireline, sealing off well fluids within the Stuffing Box.

Figure E.10 - Hydraulic Packing Nut

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E.2.8 Grease Injection Head To supply grease under pressure the following equipment is required to rig up the Grease Injector Head: • High pressure grease pump • Grease reservoir • Compressor • Hoses • Wiper box • Grease injector head assembly • Sheave • Crane or drawworks. The Grease Injection Head; See Figure E.11, is designed to effectively seal off stranded wirelines, such as fishing and logging cables. The Grease Injection Head utilises grease or honey oil, pumped under high pressure from a grease pump, into a very small annular space between the outside of the wire and the inside of a tube covering it. The high pressure fluid provides two sealing mechanisms: • Since stranded lines have interstices between the strands and between layers which cannot be packed off in a more direct, conventional manner, the sealing fluid fills these spaces, depriving the well fluid of escape paths inside and around the wire. • The sealing fluid in the small annular space is held at a higher pressure than that in the well, forming a barrier to the flow of wellhead fluids and gases. This results in the complete sealing and also lubrication of the wireline which reduces friction. NOTE: When calculating the amount of stem required to overcome the well pressure, a percentage must be added to compensate for friction. The Grease Injection Control Head is composed of three flow tube sleeves, a flow tube sleeve coupling, a quick union pin end, a flow hose and a line rubber and hydraulic packing nut assembly at the upper end.The amount of flow tube sleeve used depends on the well pressure. For 3/16" Braided Line: 3 flow tubes 0 - 4,000 psi. 4 flow tubes 4,000 - 6,000 psi. 5 or 6 flow tubes 6,000 - 10,000 psi. The flow tubes are close-fitting around the wireline and they, along with the flow tube sleeves, form the main length of the grease head. This appreciable length affords sufficient length to form an effective pressure barrier. The flow tube sleeves are simplified body parts which hold the various other components rigidly together and seal them. In addition, they are made of a very hard metal and the wire predominantly bears on them, preventing wear on the other parts. The flow tube coupling forms a junction for the flow tubes and also as the point of entry for the grease.


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Grease Out Flow Tube

Flow Tube

Grease In Flow Tube

Quick Union

Figure E.11 - Grease Injection Head

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The Hydraulic Packing Nut is a simple but efficient device which is remotely operated by a hydraulic hand-pump assembly.The Hydraulic Packing Nut is actuated by pumping pressure into the cylinder. When a complete seal is established, the pressure is maintained by closing the valve at the hand pump assembly. The pressure may be relieved by opening the valve and thus relaxing the seal.Thus, the piston in the packing nut is retracted by a strong spring when the pressure is relieved from the piston. The body has a port into which is assembled a flow hose to lead off any seepage that migrates through the line and finds its way above the two flow tubes. The optional differential pressure regulator valve, when used, controls the flow of grease to the control head which is supplied by the grease supply system. In all cases, the grease is delivered at a pressure of 350 psi. to 400 psi. greater than the wellhead pressure. E.2.9 Flow Tubes A range of flow tubes; See Figure E.12 are available with small increments of IDs so as to provide an effective seal over the life of a wireline which reduces in size with usage. The OD. of the line should be measured and the size of the tubes selected for the closest fit (ID. of flow tubes should be 0.004 in. - 0.006 in. larger than OD. of wireline). Slip each tube in turn over the wire and physically check that they do not grip the wire as this can lead to ‘bird caging’ of the outer strands when running in the well.This is an effect where the drag on the outer strands gradually holds them back with regard to the inner strands so they become loose and spring out from the cable like a bird’s cage until they jam at the packing nut. If the packing nut is too tight it can also cause this same effect. (Alternatively, if the tubes are too big, they will not create an effective barrier and too much grease will be wasted.)

Figure E.12 - Flow Tube Schematic © Aberdeen Drilling Schools 2001

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E.2.10 Grease Injection System The system is designed to deliver grease as demanded under continuous operation within the parameters of a single pump unit. There are two circuits on the unit for control/drive air and grease and both are described below: a) Grease System The system pump draws grease from the grease reservoir through the pump suction tube and it is pumped to the outlet port which is split into two lines. One line delivers grease to the control panel vent valve which allows the operator to vent grease pressure to atmosphere via a short hose into an alternate grease reservoir which is not in use (this is normally permissible as grease from this source should be clean; however, care should be taken to isolate grease from airborne contamination).The other line is the grease supply line plumbed via a rotary valve to hose storage reels and then to the appropriate grease head; See Figure E.12. The grease return line via the hose reel, rotary valve, and system pressure gauge leads to a system pressure control vent valve from which the vented grease flow rate is controlled. This grease is plumbed (now at atmosphere pressure) through a short flexible hose to a waste grease container and should not be re-used as this may be contaminated. Excessive grease returns will indicate incorrectly sized flow tubes. NOTE: If a 5/16" line is used, the supply pump must be fitted with at least a 3/4" ID. hose to ensure adequate supply to retain seal. b) Pneumatics The drive air enters the unit via a bulkhead quick connect to a pressure control valve which is pilot controlled from the control panel and also acts as a stop/start control. A separate supply is plumbed to the control panel into a three way, two position valve. Position one is where the supply is blocked with the reservoir vented to atmosphere, position two is where the supply air is directed to the reservoir via the reservoir lid pressure controller; both allow the operator an auto pre-set reservoir pressurisation or vent to atmosphere in one control valve.

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Figure E.13 - Grease Injection Rig Up


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WARNING: HIGH PRESSURE - Never allow any part of the human body to come in front of or in direct contact with the grease outlet. Accidental operation of the pump could cause an injection into the flesh. If injection occurs, medical aid must be immediately obtained from a physician. WARNING: COMPONENT RUPTURE - This unit is capable of producing high fluid pressure as stated on the pump model plate.To avoid component rupture and possible injury, do not exceed 75 cycles per minute or operate at an air inlet pressure greater than 150 psi. (10 bar). WARNING: SERVICING - Before servicing, cleaning or removing any component, always disconnect or shut off the power source and carefully relieve all fluid pressure from the system. E.2.11 Safety Check Union This device can be included in braided/stranded wireline Lubricator hook-ups just below the Grease Injection Head. The wire is threaded through both these units and in the event that the wire breaks and is blown out of the Grease Injection Head, the well pressure will automatically shut off by the Safety Check Union. Shut-off is accomplished by the velocity of the escaping well effluents causing a piston to lift a ball up against a ball seat; See Figure C.14. Well pressure holds the ball against the seat.This device does in fact fulfil the same function as the internal WirelineValve in the solid wireline Stuffing Box.As with all Lubricator equipment, this Safety Check Union is furnished with Quick Unions.

Figure E.14 - Safety Check Union E-20


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COILED TUBING SURFACE WELL CONTROL EQUIPMENT

F.1

INTRODUCTION

F.2

BARRIER PRINCIPLES

F.3

PRESSURE CONTROL EQUIPMENT

F.4

OPERATIONAL PLANNING AND SAFETY

F.5

EMERGENCY PROCEDURES

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- COILED TUBING SURFACE WELL CONTROL EQUIPMENT

F.1 INTRODUCTION When planning a Coiled Tubing operation, include a rough draft on well control requirements for the particular application. One of the main reasons for this is that it may be a significant factor regarding the amount of items required in the well equipment stack-up. Both the well characteristics and the type of operation should be considered as they determine the minimum size and type of well control devices that need to be employed to safely and successfully conduct the programme. In Coiled Tubing operations both internal and external pressure control must be assessed. ‘Internal’ refers to the inside of the coiled tubing and ‘External’ to the coiled tubing annulus. The typical Well Control Stack is: • Stripper • BOP • Riser • Shear Seal Starting from the top of the tree, many operators utilise a single shear/seal device which is flanged to the tree irrespective of well conditions and the operation to be carried out. This is generally a tertiary barrier. Other operators only use a shear/seal device when they deem it applicable.The bore diameter and cutting capabilities of the shear/seal will depend largely on the type of toolstring. On top of the Xmas tree or a shear/seal, if used, is a crossover flange to quick union sectional riser continuing to the operating level, i.e. rig floor or platform deck, with any additional stick up height that is required. The BOP is mounted directly on top of the riser using any crossovers which are required.The BOP can be either be a conventional quad BOP, or the later style Comb BOP’s. Combi’s were developed to be shorter and therefore have less stick up. The stripper/packer or stuffing box attaches to the top of the BOPs.This piece of equipment is normally bolted to the underside of the injector head. A tandem stripper/packer or even an annular BOP can be installed between the standard stripper/packer and the BOP for additional safety particularly when the well conditions may cause premature stripper rubber wear. Whichever combination of BOPs is selected in the stack-up for an operation, it should include a closed barrier to allow safe stripper/packer rubber replacement and a backup barrier.


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F.2 BARRIER PRINCIPLES A combination of pressure control barriers are used in coiled tubing operations to provide both internal pipe and external pipe pressure control. For external pressure control the barriers during normal operations are stripper/packers, annular BOPs and BOP pipe rams. Strippers or annular BOPs are considered as primary barriers and the BOPs as secondary barriers. The internal barrier during normal operations are double BHA check valves. Both check valves together are considered as the primary barrier and the BOP cutter rams secondary. BOP shear/seal rams or cutter gate valves are barriers on both sides and are considered tertiary barriers. F.3 PRESSURE CONTROL EQUIPMENT F.3.1 Check valves Check valves are installed in the coiled tubing BHA above the disconnect sub. They provide primary inside pressure control. The four most common types used are shown in Figure F.1, Figure F.2, Figure F.3, and Figure F.4 F.3.2 Stripper/Packer The stripper/packer is located at the top of the pressure control stack-up attached to the injector head and is the primary pressure control barrier. It is constantly energised throughout the coil tubing operation to effect a seal against the tubing; See Figure F.5, Figure F.6, Figure F.7 and Figure F.8. As it is in constant use, on high pressure or gas wells, the elastomer sealing element can wear out quite rapidly, hence the contingency requirement for a back-up stripper or annular BOP. An example of such a rig up is shown in Figure F.11. As stated above, this back-up unit would only be brought into use if the first packing element failed. Used in conjunction with the tubing rams in the BOPs, this provides an additional barrier and allows safer access to change the worn elastomers in the first stripper. In other circumstances the back-up stripper may be used to allow operations to continue without having to repair the first stripper Because of the increased height due to using tandem stripper/packers, a new development introduced is the radial stripper/packer; 4.This reduces the stack up height by about half and makes changing the elastomers a very simple task.

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Figure F.1 - Ball Check Valve

Figure F.2 - Dome Check Valve © Aberdeen Drilling Schools 2001

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Figure F.3- Flapper Check Valve

Figure F.4 - Removable Cartridge Flapper Valve

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Figure F.5 - Stripper/Packer


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Figure F.6 - Side Door Stripper/Packer

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Figure F.7 - Tandem Sidedoor Stripper/Packer


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Figure F.8 - Radial Stripper/Packer

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F.3.3 BOPs The BOP is the secondary barrier in pressure control. As a failsafe device, the BOP should only be operated as a safety device and with careful consideration and not used for any other use such as a means of “parking” the tubing while at depth. A standard quad BOP is configured with four rams; See Figure F.9 and Figure F.10 From top to bottom: • Blind Rams Blind rams only seals on open hole when the elastomers on each ram meet and seal. If there is pipe across the ram area the seal cannot be effected. • Shear Rams Shear rams have the ability to cut tubing. When using C/T logging i.e. tubing with logging cable through it, the shear rams must have the capability to cut both. There is no seal on this function. Extreme caution should be taken when functioning any of the rams as accidental functioning of the shear rams could potentially be very dangerous and at best causes a fishing job. • Slip Rams The slip ram is designed to hold the full tubing weight, and it too has no sealing function.The slip toolface can mark the tubing significantly and induce an area where premature cracking can occur. Caution should be used when considering the use of these rams as the slip toolface can significantly mark the tubing and induce an area where premature cracking can occur. • Tubing Rams Tubing rams are used to effect a seal against the tubing.Wellbore pressure aids in the sealing of the ram when a differential is created, by bleeding off above. Both this ram and the blind ram do not hold pressure from above. A Combi BOP incorporates the functions of two upper and the two lower types of rams into one unit and in so doing reduces rig up height and simplifies the controls system. However, it would be necessary to alter the well control procedures accordingly. A triple Comb is a model which has two combination slip/tubing rams as well as the combination shear/blind rams. A triple Comb combined with two radial stripper/packers provides a shorter stack up than a conventional stack-up; See Figure F.11.


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Figure F.9 - Quad BOP

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Figure F.10 - EH34 Quad BOP


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F.3.4 Shear/Seal This device is usually a 61/8" bore Comb ram with single cut and seal rams; See Figure F.12. This provides a single cut/seal function for installation safety and is the tertiary barrier. In the event of a platform emergency, a designated person is responsible for it’s closure but normally the platform manager’s permission is sought time permitting. To illustrate the main components of a typical hydraulic ram, a sectioned drawing of a shear/ seal actuator is illustrated; See Figure F.13. Figure F.14 shows the height of a typical stack up arrangement using a dual Comb on the tree, a triple Comb BOP, a quick union connector, a tandem and standard stripper/packer.

Figure F.11 Pressure Control Stack Up

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Figure F.12 - Shear/Seal Single BOP


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Figure F.13 - Shear/Seal Actuator Assembly

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Figure F.14- Pressure Control Stack Up


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F.4 OPERATIONAL PLANNING AND SAFETY F.4.1 Introduction Initially look at the different factors which control any Coiled Tubing operation.These factors when combined in the right order, and planned properly, will see the completion of a successful coiled tubing operation. F.4.2 Operational Considerations Gas Well Gas wells cause undue wear to stripper rubbers and, hence, it may be necessary to provide an additional stripper/packer, to complement the standard package. High Wellhead Pressure Use of coiled tubing in high pressure situations, require a thorough check of certain aspects pertaining to the well control equipment. For example, the pressure rating of the equipment, back-up stripper/packer or annulus preventer and the capability of the hydraulic system to, either, shear or effect a proper seal around the tubing Toolstring Length The operation will dictate the length of the tool string which in turn may affect the rig up, e.g. length of riser, pick up height of the injector and stick up height of well control equipment. See Figure F Toolstring Deployment Systems Novel deployment systems have been developed for the deployment of extra long toolstrings such as TCP type perforating guns.These systems provide barrier protection when the toolstring is being made up and lubricated into the well. Such systems may require the assistance of a wireline unit and crew. F.4.3 Working Location Type of Rig A semi-submersible drilling or workover vessel requires the addition of a heavy duty lifting frame installed between the block and the surface tree in which to support the injector and BOPs. Drilling rigs can usually accommodate the width of injectors quite easily but in certain circumstances the “A” frame height can be restrictive. Workover rigs tend to have smaller “V” doors than conventional drilling rigs, and dimensions of this should be checked against the injector size available. On land well operations where there is no means of holding back the injector against the pull of the tubing from the reel, an adjustable stand is required to support the forces with the ground. F-16


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Rig Floor Equipment There should be enough rig floor tuggers capable of pulling the injector into position for stabbing onto the BOP with sufficient lifting capacity. There should be two for the injector positioning, one to install the toolstring and one or more for man riding.The tie down points must be designed and certified for the job. Rig floor working space should not be restricted with unnecessary items of equipment or tubulars in the derrick. The main access and emergency exit points should not be restricted. Refer to Figure F.15

Figure F.15 - Radius of Safety


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F.4.4 Pressure Control Equipment Considerations The style of stripper/packer in relation to the operation requires consideration. On a conventional stripper/packer it may take over 45 minutes to change the elastomers with pipe in the hole. To change the elastomers in a side door stripper/packer, may take as little as 5 minutes. A tandem stripper/packer should be employed to serve as an additional well barrier in high wellhead pressure situations. A tandem stripper/packer it will add approximately 4 ft. to the stick up height which needs to be considered. BOPs are now available in several different configurations. The standard is a quad, i.e.; with four separate ram functions. The trend now is to combine the rams to form Combi BOPs. The most common configuration is the Triple Combi. This BOP combines the two top functions and eliminates the need to pull pipe as is necessary after the shear on the quad. The shear/seal is a large single cut and seal device. This is normally flanged on top of the wellhead and used only as a last resort.The shear/seal usually is of a size equal to the wellbore, and is capable of cutting the toolstring. Control Hoses On a semi-submersible the injector and the BOPs may be a considerable height above the drillfloor. This must be considered with the position of the power pack and control house, whereby extensions to the control hoses may be required. Similarly on a platform, if the coiled tubing is to be run from the pipe deck to the skid deck, the control hoses may again require extensions. Support Stand The standard type support stand is manually operated and requires constant monitoring in live well situations. If the operation is performed with the well on production, and cold liquids introduced through the coiled tubing this will cause the riser to contract, the support stand may become trapped under the injector. A hydraulic support type stand has built in relief valves to release the pressure should the riser shrink. Tie Back Points The use of tie down points requires the need to have similar tie back points on the injector. Under normal circumstances injectors are not fitted with this facility. If the frame is to be used ensure that the attaching points are tested fit for the job. Pre-Job Saftey Checks • Have the BOPs been adequately pressure test? • What is the maximum expected well pressure? • Can the injector snub against this pressure without buckling the coiled tubing? • Will the shear rams cut the coiled tubing against this pressure? • Is a tandem stripper/packer required? • Is an extended tool, pressure deployed system required? F-18


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F.5 EMERGENCY PROCEDURES All procedures are dependent on a combination of the position of the tool string in the well bore, and the wellhead pressure. F.5.1 Platform Shutdown In the event of a platform shutdown the well must be made safe. To carry out this operation does not require the full crew, and only one operator should remain to function the well control equipment, as outlined below: • Stop the Coiled Tubing • Stop pumping fluids • Close the tubing rams • Close the slip rams • Await further instructions • A decision should be made to close the shear/seal on top of the wellhead. F.5.2 Stripper/Packer Element Leak The Stripper/packer should be energised sufficiently with hydraulic pressure, so that it will contain any well bore fluids, but not restrict the running of the coiled tubing. Should the element start leaking and it cannot be energised to stem the leak, the following should be implemented: • Stop the coiled tubing • Close the tubing rams • Inform the company representative • Form a remedial plan. F.5.3 Leak Between the Top of the Tree and the Stripper/Packer In the above situation the following should be implemented: • Stop the coiled tubing • Inform the company representative • Depending on the severity of the leak, a decision should be taken as to closing the shear seal. F.5.4 Tubing Pinhole Leak The tubing develops a leak at the surface. In this situation the procedure is quite simple: • Stop the coiled tubing. • Inform the company representative.


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• Wait for the pressure in the tubing to bleed down. • If the pressure drops and the check valves are holding. • Pull out of the hole spooling the pinhole onto the reel. F.5.5 Tubing Ruptures The tubing ruptures as it comes over the gooseneck and separates. Initially this can be a potentially hazardous, and serious situation.The seriousness is dependant on the tubings internal pressure, the wellhead pressure, and the type of medium within the tubing: • Stop the coiled tubing. • Inform the company representative. • Let the pressure in the tubing bleed down. • If the pressure drops and the check valves are holding, pull rupture to deck level and splice tubing. • If it appears that the check valves are not holding, the shear seal should be closed and the well secured. • Prepare to fish coiled tubing. F.5.6 Tubing Separates Downhole The tubing separates downhole. In this situation the procedure becomes a little more complicated, but less hazardous if handled correctly: • Stop the coiled tubing. • Establish approximately at what point the tubing parted. • There is a need to consider the possibility of killing the well. • Assuming the well is in a safe condition POOH slowly to a pre-determined depth. • Start closing the swab valve counting the turns to establish when the coiled tubing is above the tree. • Once the end of the tubing is above the swab shut in the well using the upper and lower master valves. • Bleed down the riser and pull the end of the tubing to surface. • Prepare to fish coiled tubing.

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HYDRAULIC WORKOVER / SNUBBING EQUIPMENT AND HAZARDS

G.1

INTRODUCTION

G.2

BARRIER PRINCIPLES

G.3

PRESSURE CONTROL REQUIREMENTS

G4

SNUBBING EQUIPMENT

G.5

BOTTOMHOLE ASSEMBLIES

G.6

IDENTIFIED SNUBBING / HWO HAZARDS

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G. APPENDIX - HYDRAULIC WORKOVER/SNUBBING EQUIPMENT AND HAZARDS G.1 INTRODUCTION It is essential that prior to any snubbing/HWO operation the safety issues are addressed. Reference should be made to relevant sections of the appropriate Safety Manual. At the safety meeting all aspects of the operation and detailed contingency plans should be discussed. Snubbing/HWO emergency procedures will form the basis of these contingency plans. Of particular importance are the aspects of Well Control Procedures. Under no circumstances should safety be compromised. Procedures should be observed, work permits strictly adhered to, and equipment operated within designed parameters. Aspects of well control must be included in the planning and equipment selection process. Snubbing operations are performed on live wells and particular emphasis must be given to the required well control competencies and equipment to be used for each individual application. G.2 BARRIER PRINCIPLES A combination of pressure control barriers are used in snubbing operations to provide both internal pipe and external pipe pressure control similar to coiled tubing operations addressed in Appendix F. For external pressure control the barriers during normal operations are stripper rams, annular BOPs and BOP pipe rams. The stripper rams or annular BOPs are considered as primary barriers and the safety BOPs as secondary barriers. Internal barriers during normal operations are double BHA check valves. The lowermost check valve is considered the primary barrier with the upper being the secondary.An advantage of snubbing over coiled tubing is that a wireline installed check valve can be run into the BHA on failure of the other check valves and is the secondary barrier. BOP shear/seal rams are barriers on both sides and are considered tertiary barriers. G.3 PRESSURE CONTROL REQUIREMENTS Pressure control requirements for workover operations are covered API RP 53.These documents do not, however, address snubbing operations. The expertise within the industry is with a small group of specialised contractors, who posses the required equipment and competence. However, it is incumbent upon the asset holder (or his delegated representative) to ensure that all activities carried out on the asset (the well) are conducted in a manner to provide for complete well control.


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G.4 SNUBBING EQUIPMENT Most of the equipment used in snubbing operations consists of ram and annular type BOPs and chokes which are already described in Appendix A. A typical snubbing rig ups for various well pressures, pipe sizes are shown in Section 7. They effectively consist of the equipment described in the following sections. The configuration of a snubbing stack from top to bottom is generally: • Stripper Bowl (Optional) • Stripper Rams/Annular BOPs Used to seal around the pipe when snubbing. If using more than one pipe size there must be a set of stripper rams for each pipe size. The rams are dressed with inserts to allow stripping of the pipe. • Safety Rams Safety rams are essentially the same as stripper rams except they are used solely for safety. Safety may also be situated below the blind and shear rams. • Blind Rams Blind rams are used to seal off the open hole. They seal when the elastomers on each ram meet. They will not seal when there is pipe across them. • Shear Rams Shear rams have the ability to cut the pipe. There is no seal on this function. Extreme caution should be taken when functioning any of the rams as accidental functioning of the shear rams could potentially be very dangerous and at best causes a fishing job. G.4.1 Stripper Bowls Stripper bowls are pressure containment devices for use during low pressure pipe moving operations, usually below 2,000psi. At these pressures, pipe running speed and efficiency can be increased by using these devices for the primary annular seal rather than the normal blowout preventers, since the airlock cycle operations are eliminated. G.4.2 Stripper BOPs For upset pipe two stripper pipe rams are used to effect a seal on the outside of the pipe.These rams are operated by the unit operator from a control panel located in the basket. They are regular ram type BOPs which are opened and closed in sequence to allow the upsets to pass into the well. The pressure trapped between the two stripper rams when the lower stripper ram is closed is bled off through a choke in the bleed off line.To open the lower stripper ram after closing the upper ram, pressure is equalised across the lower ram by the equalising loop.

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When more than one pipe size is being run, a set of stripper BOPs for each size must be included in the rig up. To repair a damage stripper ram, normally two safety pipe rams are closed on the pipe to provide two barriers (in some areas of the world this convention is not recognised). G.4.3 Annular BOPs Tandem annular BOPs are normally used when running non upset pipe. One of the annulars is contingency for damage to the first annular.There is a great advantage when using annulars in that there is no requirement for a bleed off or equalising line and, therefore, running speed are faster. G.4.4 Safety BOPs Safety BOPs are used for safety only.They are closed on the pipe to effect a seal when there is either a leak downstream or when the stripper or annular rubbers need redressing.They differ from the stripper rams in that they may be dressed primarily for sealing against the pipe rather than stripping. G.4.5 Shear/Blind BOPs A set of shear and blind rams are installed as a tertiary barrier. To prevent the pipe dropping after severance, additional safeties are added below the shears. G.4.6 Testing Requirements After the snubbing unit is installed, the integrity of the wellhead and the well control equipment must be established before operations commence.This is accomplished by a series of pressure test procedures to sequentially: • Test the tertiary pressure control system against a closed Xmas tree valve. • Test the secondary control system against the tertiary system. • Test the primary control system against the tertiary system.


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Work Basket

Fluid Storage And

Gin Pole

Choke

Processing

System

Stationary Slips Hoses

Work Window Tool House

Fill Line

Stripper Bowl Hanger Flange

Mud Pump

Drain Line

Bleed

Tool Box

Equalise Line

Line Ground Based BOP

Control Units

Spares

Choke Line

Upper Kill Line

Power Unit Fuel

Figure G.1 - Typical HWO/Snubbing Layout G-4


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G.5 BOTTOMHOLE ASSEMBLIES The configuration of BHAs with regard to check valve and back pressure valve location and function is essential for safety at the start of running or the end of pulling a workstring: • BPVs used must be as strong as the tubing and are located at the bottom of the string for normal operations. However they may be placed higher if using gases for foam jetting or nitrogen lifting, reducing the inventory of gas which may blow back if there is a failure in the pumping equipment lines. • When using abrasive fluids such as cement, it is advisable to install pump-out type valves in the event of plugging or flow cutting. They are also used if reverse circulating is required. • Standard* back pressure valve configurations are shown in Figure G.2. The configurations in A and C are preferred. In B it must be closely checked to ensure the wireline plug can be set in the nipple. A long end cap may hold up on the top back pressure valve and prevent the lock mandrel from setting in the nipple.The non-standard configuration in D may be too long to allow closing in the well when the nipple is at the top of the mast. When using pump-out BPVs, the configuration in E should be used but the pump-out ball for expending the BPVs must first be passed through the nipple to check clearance. * Standard in this context means a practise which has become a “standard” within the service companies who provide snubbing/HWO services to the industry and is not an institutionalised type standard.


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E is a special configuration when having to use a pump out check valve for operational reasons. Due to the check valve being expendable by pumping down a drop ball, another check valve cannot be installed above it. For this reason, primary inside well control is only the single check valve. If expended, the secondary system is a wireline check valve installed in the nipple by wireline.

Figure G.2 - BHA Configuration

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G.6 IDENTIFIED SNUBBING/HWO HAZARDS There are three main areas involving HWO activities where hazards are identified: • HWO operation. • Well control. • Use of HWO auxiliary equipment.

Figure G.3 - Stripper Assembly


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APPLICATION

IDENTIFIED HAZARDS

CONTROL MECHANISM

A. HWO Operation

1. Power Pack Failure

Pre-Emptive:

Engine Failure

Conduct maintenance procedures and ensure engine is fully serviced with oil and fuel.

Engine out of fuel

Re-active: Immediately set Heavy slips on pipe in the hole, (Snubber stationery if in the light mode) close in pipe rams on tubing.

2. Hydraulic Failure

Pre-Emptive:

Hydraulic hose bursting

Conduct proper check on all hose connection valves and pumps.

Valve seizure

Function test all Hydraulically moving parts.

Insufficient oil in Hydraulic Reservoir

Ensure sufficient Hydraulic oil is in the reservoir. Re-active: Make sure unit is secure prior to shutting down engine for repairs.

3. Slip Failure

Pre-Emptive:

Tubing Sliding Through Slips

Ensure correct pressures are maintained for opening and closure of slips. Ensure slip inserts are free from grease, pipe dope and scale whilst RIH or POOH. Re-active: Close in all slips and secure with clamp prior to changing out worn slip inserts.

4. Stripper BOP Failure

Pre-Emptive:

Rams closing too slow

Ensure correct preventer pump pressure is maintained for the rams being used.

Valves sticking whilst opening or closing

Ensure equalise and bleed-off valves are functioning properly (as BOP will not open if pressure is trapped between rams). Re-active: Close in tubing rams below stripper BOP and manually lock in. Bleed off pressure. Open rams and change out stripper inserts. Ensure valves are greased properly with correct grease.

5. Jack Movement

Pre-Emptive:

Slow movement of jack

Ensure all jack pumps are at correct settings. Ensure sufficient hydraulic oil is in reservoir. Check munsen tyson valve is functioning properly.

Jack jumps when moving up or down

Ensure counter balance valves are operational and free from grit. Re-active: Secure tubing in well in heavy slips. Check all settings for pumps, and that pumps are all functional. Open travelling slips and check movement on jack without pipe.

Continued

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B. HWO Well control

1. BPV Failure

Pre-Emptive:

Gas or liquid flowing from top of tubing

Ensure back pressure valves are maintained properly.

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CONTROL MECHANISM

Check springs ball and seats are not worn or corroded. Ensure tool joints are made up to correct torque and seals are OK. Pipe dope or scale falling on top of BPVs. Tubing is rabbited and clear of debris Tool joints are doped properly

Re-active: When running or pulling under pressure ensure TIW valves are used at every joint whilst making up or breaking out tubing. Renew springs and ball and seats. If necessary, drop dart plug and pump into nipple.

C. Use of HWO Auxiliary Equipment

1. Auxiliary Equipment Gin Pole, Counterbalance Winch Tongs

Pre-Emptive:

Equipment Failure

Ensure equipment is properly rigged up and maintained.

Check for defective or worn tools and equipment

Follow correct rig up and running procedures.

Slinging lifts

Follow correct lifting and slinging procedures whilst rigging up equipment. Ensure correct hydraulic system pressures are being used. Re-active: At the first sign of any wear or tear, secure unit and shut down power pack, if necessary and carry out repairs. All worn guy wires and winch cables should be changed-out. (These repairs should be done immediately.)


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EQUIPMENT SPECIFIC REQUIREMENTS

H.1

FLANGED END AND OUTLET CONNECTIONS

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H. APPENDIX - EQUIPMENT SPECIFIC REQUIREMENTS H.1 FLANGED END AND OUTLET CONNECTIONS H.1.1 General - Flange Types And Uses Three types of end and outlet flanges are controlled by this specification: • 6B, 6BX and segmented. • 6B and 6BX flanges may be used as integral, blind or weld neck flanges. Type 6B may also be used as threaded flanges. Some type 6BX blind flanges may also be used as test flanges. Segmented flanges are used on dual, triple, and quadruple completion wells and are integral with the equipment. H.1.2 Design a) Pressure Ratings and Size Ranges of Flange Types. Type 6B, 6BX, and segmented flanges are designed for use in the combinations of nominal size ranges and rated working pressure as shown in Table H.1. b) Type 6B Flanges. • General. API Type 6B flanges are of the ring joint type and are not designed for make-up face- to-face.The connection make-up bolting force reacts on the metallic ring gasket. The Type 6B flanges shall be of the through-bolted or studded design. • Dimensions (1) Standard Dimensions. Dimensions for Type 6B integral, threaded, and weld neck flanges shall conform to Table H.2, Table H.3 and Table H.4 Dimension for Type 6B blind flanges shall conform to those referenced in Table H.1 Dimensions for ring grooves shall conform to Table H.5 and Table H.6 (2)

Integral Flange Exceptions. Type 6B flanges used as end connections on casing and tubing head connections may have entrance bevels, counterbores or recesses to receive casing and tubing hangers. The dimensions of such entrance bevels, counterbores, and recesses are not covered by this specification and may exceed the B dimension of Table H.2 and Table H.4(3)

(3)

Threaded Flanges. Threads shall conform to the requirementsof the manual.


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c) Weld Neck Flanges. Bore Diameter and Wall Thickness.The bore diameter JL shall not exceed the values shown in Table H.2, Table H.3 and Table H.4. The specified bore shall not result in a weld-end wall thickness less than 87.5 percent of the nominal wall thickness of the pipe to which the flange is to be attached. Weld End Preparation. Dimensions for weld end preparation shall conform to Table H.2 Taper - When the thickness at the welding end is 3/32" or greater than that of the pipe, and the additional thickness decreases the inside diameter, the flange shall be taper bored form the weld and at a slope not exceeding 3 to 1. NOTE: Due to smaller maximum bore dimensions,Type 6B weld neck flanges are not intended to be welded to equipment in this specification.Their purpose is to bolt to another 6B flange and provide a transition to be welded to a pipe. • Flange Face. Flange face may be flat or raised on the ring, joint side and shall be fully machined. Flange back face may be fully machined or spot faced at the bolt holes. The flange back face or spot faces shall be parallel to the front face within one degree and the thickness after facing shall conform to the dimensions of Table H.2, Table H.3 and Table H.4 • Gaskets. Type 6B flanges shall use Type R or Type RX Gaskets in accordance with Section IH.1.3. • Corrosion Resistant Ring Grooves.Type 6B flanges may be manufactured with corrosion resistant overlays in the ring grooves. Prior to application of the overlay, preparation of the ring grooves shall conform to the appropriate dimensions. Other weld preparations may be employed where the strength of the overlay alloy equals or exceeds the strength of the base materials. • Ring Groove Surface. All 23˚ surface on ring grooves shall have a surface finish no rougher than 63 RMS. FLANGE SIZE RANGE SEGMENTED

RATED WORKING PRESSURE Type 6B 2,000 3,000 5,000 10,000 15,000 20,000

21/16 thru 211/4 21/16 thru 203/4 21/16 thru 11 -

Type 6BX 263/4 263/4 135/8 thru 211/4 113/16 thru 211/4 113/16 thru 183/4 113/16 thru 135/8

Dual

Triple or Quadruple

-

113/16 thru 41/16 x 41/4 -

13/8 thru 41/16 x 41/4 -

Table H.1 - Rated Working Pressure and Size Ranges of API Flanges

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Figure H.1 - Type 6B Blind Flanges

Figure H.2- Weld End Preparation for Type 6B and 6BX Weld Neck Flanges


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RING GROOVE MUST BE CONCENTRIC WITH BORE WITHIN 0.010 TOTAL INDICATOR RUNOUT

BOLT HOLE CENTRELINE LOCATED WITHIN 0.03 OF THEORETICAL BC AND EQUAL SPACING

Figure H.3 - Type 6B Flanges

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BASIC FLANGE DIMENSIONS Nominal Size & Bore of Flange

21/16 29/16 31/8 41/16 71/16 9 11 135/8 163/4 211/4

Max. Bore

Outside Diameter of Flange

Tolerance

B

OD

OD

C

K

+0.06 +0.06 +0.06 +0.06 +0.12 +0.12 +0.12 +0.12 +0.12 +0.12

0.12 0.12 0.12 0.12 0.25 0.25 0.25 0.25 0.25 0.25

4.25 5.00 5.75 6.88 9.50 11.88 14.00 16.25 20.00 25.00

2.09 2.59 3.22 4.28 7.16 9.03 11.03 13.66 16.78 21.28

6.50 7.50 8.25 10.75 14.00 16.50 20.00 22.00 27.00 32.00

Max. Diameter Chamfer of Raised Face

Total Basic Diameter Thickness Thickness of of of Hub Flange Flange T Q X

1.31 1.44 1.56 1.81 2.19 2.50 2.81 2.94 3.31 3.88

1.00 1.12 1.25 1.50 1.88 2.19 2.50 2.62 3.00 3.50

3.31 3.94 4.62 6.00 8.75 10.75 13.50 15.75 19.50 24.00

BOLTING DIMENSIONS Diameter of Bolt Circle

Number of Bolts

Diameter of Bolts

Diameter of Bolt Holes

Bolt Hole Tolerance

Length of Stud Bolt

BC

Ring number R or RX

LSSS

5.00 5.88 6.62 8.50 11.50 13.75 17.00 19.25 23.75 28.50

8 8 8 8 12 12 16 20 20 24

5/ 8 3/ 4 3/ 4 7/ 8

1 11/8 11/4 11/4 11/2 15/8

0.75 0.88 0.88 1.00 1.12 1.25 1.38 1.38 1.62 1.75

+0.06 +0.06 +0.06 +0.06 +0.06 +0.06 +0.06 +0.06 +0.09 +0.09

4.50 5.00 5.25 6.00 7.00 8.00 8.75 9.00 10.25 11.75

23 26 31 37 45 49 53 57 65 73

HIUB AND BORE DIMENSIONS Nominal Size and Bore of Flange

Hub Length Hub Length Threaded Threaded Casing Line Pipe Flange Flange LL

21/16 29/32 31/8 41/16 71/16 9 11 135/8 163/4 211/4

1.75 1.94 2.12 2.44 2.94 3.31 3.69 3.94 4.50 5.38

LC

3.50 4.50 5.00 5.25 3.94 4.50 5.38

Hub Length Welding Neck Line Pipe Flange LN

Neck Diameter Welding Neck Line Pipe Flange HL

Tolerance

Maximum Bore of Welding Neck Flange

HL

JL

3.19 3.44 3.56 4.31 4.94 5.56 6.31 -

2.38 2.88 3.50 4.50 6.63 8.63 10.75 -

+0.09/-0.03 +0.09/-0.03 +0.09/-0.03 +0.09/-0.03 +0.16/-0.03 +0.16/-0.03 +0.16/-0.03 -

2.07 2.47 3.07 4.03 5.76 7.81 9.75 -

Table H.2- Basic Flange, Bolt and Hub and Bore Dimensions for 2000psi Rated Working Pressure © Aberdeen Drilling Schools 2001

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BASIC FLANGE DIMENSIONS Nominal Size and Bore of Flange

21/16 29/16 31/8 41/16 71/16 9 11 135/8 163/4 203/4

Max. Bore

Outside Diameter of Flange

Tolerance

Max. Chamfer

B

OD

OD

C

K

+0.06 +0.06 +0.06 +0.06 +0.12 +0.12 +0.12 +0.12 +0.12 +0.12

0.12 0.12 0.12 0.12 0.25 0.25 0.25 0.25 0.25 0.25

4.88 5.38 6.12 7.12 9.50 12.12 14.25 16.50 20.62 25.50

2.09 2.59 3.16 4.09 7.09 9.03 11.03 13.66 16.78 20.78

8.50 9.62 9.50 11.50 15.00 18.50 21.50 24.00 27.75 33.75

Diameter Total of Raised Thickness Face of Flange

Raised Thickness of Flange

Diameter of Hub

Q

X

T

1.81 1.94 1.81 2.06 2.50 2.81 3.06 3.44 3.94 4.75

1.50 1.62 1.50 1.75 2.19 2.50 2.75 3.12 3.50 4.25

4.12 4.88 5.00 6.25 9.25 11.75 14.50 16.50 20.00 24.50

BOLTING DIMENSIONS Diameter of Bolt Circle

Number of Bolts

Diameter of Bolts


Length of Stud Bolts

Bolt Hole Tolerance

Ring Number R or RX

LSSS

BC

6.50 7.50 7.50 9.25 12.50 15.50 18.50 21.00 24.25 29.50

7/ 8

8 8 8 8 12 12 16 20 20 20

1.00 1.12 1.00 1.25 1.25 1.50 1.50 1.50 1.75 2.12

1 7/ 8 11/8 11/8 13/8 13/8 13/8 15/8 2

+0.06 +0.06 +0.06 +0.06 +0.06 +0.06 +0.06 +0.06 +0.09 +0.09

6.00 6.50 6.00 7.00 8.00 9.00 9.50 10.25 11.75 14.50

24 27 31 37 45 49 53 57 66 74

HUB AND BORE DIMENSIONS Nominal Size and Bore of Flange

21/16 29/16 31/8 41/16 71/16 9 11 135/8 163/4 211/4

Hub Length Threaded Line Pipe Flange

Hub Length Threaded Casing Flange

Hub Length Tubing Flange

Hub Length Welding Neck Line Pipe Flange

Neck Diameter Welding Neck Line Pipe Flange

Tolerance

Maximum Bore of Welding Neck Flange

LL

LC

LT

LN

HL

HL

JL

4.31 4.44 4.31 4.81 5.81 6.69 7.56 -

2.38 2.88 3.50 4.50 6.63 8.63 10.75 -

+0.09/-0.03 +0.09/-0.03 +0.09/-0.03 +0.09/-0.03 +0.16/-0.03 +0.16/-0.03 +0.16/-0.03 -

1.94 2.32 2.90 3.83 5.76 7.44 9.31 -

2.56 2.81 2.44 3.06 3.69 4.31 4.56 4.94 5.06 6.75

3.50 4.50 5.00 5.25 4.94 5.69 6.75

2.56 2.81 2.94 3.50 -

Table H.3 - Basic Flange, Bolt and Hub and Bore Dimensions for 3,000 psi. Rated Working Pressure

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BASIC FLANGE DIMENSIONS Nominal Maximum Outside Size & Bore Diameter Bore of of Flange Flange

21/16 29/16 31/8 41/16 71/16 9 11 135/8 163/4

Tolerance Maximum Diameter Chamfer of Raised Face

B

OD

OD

C

2.09 2.59 3.22 4.28 7.16 9.03 11.03 13.63 16.78

8.50 9.62 10.50 12.25 15.50 19.00 23.00 -

+0.06 +0.06 +0.06 +0.06 +0.12 +0.12 +0.12 -

0.12 0.12 0.12 0.12 0.25 0.25 0.25 -

K

4.88 5.38 6.62 7.62 9.75 12.50 14.63 -

Total Basic Thickness Thickness of Flange of Flange

Ring NumberR or RX

T

Q

X

1.81 1.94 2.19 2.44 3.62 4.06 4.69 -

1.50 1.62 1.88 2.12 3.25 3.62 4.25 -

4.12 4.88 5.25 6.38 9.00 11.50 14.50 -

BOLT DIMENSIONS Diameter of Bolt Circle BC

Number of Bolts

Diameter of Bolts


6.50 7.50 8.00 9.50 12.50 15.50 19.00 -

8 8 8 8 12 12 12 -

7/ 8 1 11/8 11/4 13/8 15/8 17/8 -

1.00 1.12 1.25 1.38 1.50 1.75 2.00 -

Bolt Hole Tolerance

+0.06 +0.06 +0.06 +0.06 +0.06 +0.09 +0.09 -

Length of Stud Bolts Lsss

Ring Number R or RX

6.00 6.50 7.25 8.00 10.75 12.00 13.75 -

24 27 35 39 46 50 54 -

Table H.4 - Basic Flange and Bolt Dimensions for 5,000 psi. Rated Working Pressure


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H.1.3 Ring Gaskets General The section covers Type R, RX, and BX ring gaskets for use in flanged connections.Types R and RX Gaskets are interchangeable on 6B flanges. Only Type BX gaskets are to be used 6BX flanges.Type RX and BX gaskets provide a pressure energised seal but are not interchangeable. Design • Dimensions. Ring gaskets shall conform to the dimensions and tolerances specified in Figure H.6 and Figure H.7 and must be flat within 0.2% of ring outside diameter to a maximum of 0.015 inches. • R and RX Gaskets. 1. Surface Finish. All 23( surface on Type R and RX gaskets shall have a surface finish no rougher than 63 RMS. 2. RX Pressure Passage Hole. Certain size RX gaskets shall have one pressure passage hole drilled through their height as shown in Table H.6. • BX Gaskets. 1. Surface Finish. All 23( surface on Type BX gaskets shall have a surface finish no rougher than 32 RMS. 2. Pressure Passage Hole. Each BX gasket shall have one pressure passage hole drilled through its height as shown in Figure H.8 • Re-use of Gaskets. Ring gaskets have a limited amount of positive interference which assures the gasket will be joined into sealing relationship in the flange grooves, these gaskets shall not be reused. Materials • a. PSL 0. Gasket material for PSL 0 shall conform to appropriate standards. • b. PSL 1-4. Gasket material for these levels shall conform to appropriate standards. • c. Coating and Platings. 1. General. Coatings and platings are employed to aid seal engagement while minimising galling and to extend shelf life. Coating and plating thicknesses shall be 0.0005 inch maximum. 2. Metallic. Cadmium, zinc, copper and tin coatings or platings are acceptable for service temperatures up to 250(F. 3. Non-metallic. Non-metallic coatings are acceptable if they do not interfere with the sealing of the ring gasket. Marking Gasket shall be marked to conform to appropriate standard. Storing and Shipping Gaskets shall be stored and shipped in accordance with appropriate standards. H-8


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TOLERANCES A B&H C E F P R1 R2 23˚

(WIDTH OF RING) (HEIGHT OF RING) (WIDTH OF FLAT ON OCTAGONAL RING) (DEPTH OF GROOVE) (WIDTH OF GROOVE) (AVERAGE PITCH DIAMETER OF RING) (AVERAGE PITCH DIAMETER OF GROOVE) (RADIUS IN RINGS) (RADIUS IN GROOVE) (ANGLE)

+/-0.008 +/-0.02 +/-0.008 +/-0.02,-0 +/-0.008 +/-0.007 +/-0.005 +/-0.02 +/- MAX +/- 1/2 DEG

Figure H.4 - Type ‘R’ Ring Gaskets


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Ring No.

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Pitch Dia. of Ring & Groove

P

R 20 R 23 R 24 R 26 R 27 R 31 R 35 R 37 R 39 R 41 R 44 R 45 R 46 R 47 R 49 R 50 R 53 R 54 R 57 R 63 R 65 R 66 R 69 R 70 R 73 R 74 R 82 R 84 R 85 R 86 R 87 R 88 R 89 R 90 R 91 R 99

2.688 3.250 3.750 4.000 4.250 4.875 5.375 5.875 6.375 7.125 7.625 8.313 8.313 9.000 10.625 10.625 12.750 12.750 15.000 16.500 18.500 18.500 21.000 21.000 23.000 23.000 2.250 2.500 3.125 3.563 3.938 4.875 4.500 6.125 10.25 9.250

Width of Height of Height of Width of Radius in Ring Ring Ring Flat of Octagonal Oval Octagonal Octagonal Ring Ring

A

0.313 0.438 0.438 0.438 0.438 0.438 0.438 0.438 0.438 0.438 0.438 0.438 0.500 0.750 0.438 0.625 0.438 0.625 0.438 1.000 0.438 0.625 0.438 0.750 0.500 0.750 0.438 0.438 0.500 0.625 0.625 0.750 0.750 0.875 01.250 0.438

Depth of Groove

Width of Radius in Approx. Groove Groove Distance between made up Flanges

B

H

C

R1

E

F

R1

S

0.56 0.69 0.69 0.69 0.69 0.69 0.69 0.59 0.69 0.69 0.69 0.69 0.75 1.00 0.69 0.88 0.69 0.88 0.69 1.31 0.69 0.88 0.69 1.00 0.75 1.00 -

0.50 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.69 0.94 0.63 0.81 0.63 0.81 0.63 1.25 0.63 0.81 0.63 0.94 0.69 0.94 0.63 0.63 0.69 0.81 0.81 0.94 0.94 1.06 1.50 0.63

0.206 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.341 0.485 0.305 0.413 0.305 0.413 0.305 0.681 0.305 0.413 0.305 0.485 0.341 0.485 0.305 0.305 0.341 0.413 0.413 0.485 0.485 0.583 0.879 0.305

0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.09 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.09 0.06

0.25 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.38 0.50 0.31 0.44 0.31 0.44 0.31 0.62 0.31 0.44 0.31 0.50 0.38 0.50 0.31 0.31 0.38 0.44 0.44 0.50 0.50 0.56 0.69 0.31

0.344 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.521 0.781 0.469 0.656 0.469 0.656 0.469 1.063 0.469 0.656 0.469 0.781 0.531 0.781 0.469 0.469 0.531 0.656 0.656 0.781 0.781 0.906 1.313 0.469

0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.06 0.06 0.03 0.06 0.03 0.06 0.03 0.09 0.03 0.06 0.03 0.06 0.06 0.06 0.03 0.03 0.06 0.06 0.06 0.06 0.06 0.06 0.09 0.03

0.16 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.13 0.16 0.19 0.16 0.19 0.16 0.19 0.22 0.19 0.16 0.19 0.19 0.13 0.19 0.19 0.19 0.13 0.16 0.16 0.19 0.19 0.19 0.16 0.19

Table H.5 - Type ‘R’ Ring Gasket

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(WIDTH OF RING) (WIDTH OF FLAT) (DEPTH OF GROOVE) (WIDTH OF GROOVE) (HEIGHT OF RING) (RADIUS IN RINGS) (RADIUS IN GROOVE)

+/-0.008 +/-0.006 - 0.000 +/-0.02,-0 +/-0.008 +/-0.008 - 0.000 +/-0.02 +/- MAX

23˚

(ANGLE)

+/- 1/2 DEG

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* A PLUS TOLERANCE OF 0.008 INS FOR WIDTH A AND HEIGHT H IS PERMITTED PROVIDED THE VARIATION IN WIDTH OR HEIGHT OF ANY RING DOES NOT EXCEED 0.004 INS THROUGHOUT ITS ENTIRE CIRCUMFERENCE

Figure H.5 - API Type RX Pressure Energised Ring Gaskets

NOTE: The pressure passage hole illustrated in the RX Ring cross section in rings RX-82 through RX-91 only. Centreline of hole shall be located at mid point of dimension C. Hole diameter shall be 0.06 inches for rings RX-82 through RX-85, 0.9 inches for rings RX-86 and RX87, and 0.12 inches for rings RX-88 through RX-91.


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Ring No.

RX 20 RX 23 RX 24 RX 25 RX 26 RX 27 RX 31 RX 35 RX 37 RX 39 RX 41 RX 44 RX 45 RX 46 RX 47 RX 49 RX 50 RX 53 RX 54 RX 57 RX 63 RX 65 RX 66 RX 69 RX 70 RX 73 RX 74 RX 82 RX 84 RX 85 RX 86 RX 87 RX 88 RX 89 RX 90 RX 91 RX 99 RX 201 RX 205 RX 210 RX 215

Pitch Dia. of Ring & Groove

Outside Dia. of Ring

Width of Ring

Width of Flat

P

OD

A

C

3.000 3.672 4.172 4.313 4.406 4.656 5.297 5.797 6.297 6.797 7.547 8.047 8.734 8.750 9.656 11.047 11.156 13.172 13.281 15.422 17.391 18.922 19.031 21.422 21.656 23.469 23.656 2.672 2.922 3.547 4.078 4.453 5.484 5.109 6.875 11.297 9.672 2.026 2.453 3.844 5.547

0.344 0.469 0.469 0.344 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.531 0.781 0.469 0.656 0.469 0.656 0.469 1.063 0.469 0.656 0.469 0.781 0.531 0.781 0.469 0.469 0.531 0.594 0.594 0.688 0.719 0.781 1.388 0.469 0.226 0.219 0.375 0.469

0.182 0.254 0.254 0.182 0.254 0.254 0.254 0.254 0.254 0.254 0.254 0.254 0.254 0.263 0.407 0.254 0.335 0.254 0.335 0.254 0.582 0.254 0.335 0.254 0.407 0.263 0.407 0.254 0.254 0.263 0.335 0.335 0.407 0.407 0.479 0.780 0.254 0.126 0.120 0.213 0.210

2.688 3.250 3.750 4.000 4.250 4.875 5.875 5.875 6.375 7.125 7.625 8.313 8.313 9.000 10.625 10.625 12.750 12.750 15.000 16.500 18.500 18.500 21.000 21.000 23.000 23.000 2.250 2.500 3.125 3.563 3.938 4.875 4.500 6.125 10.250 9.250 -

Height of Outside Bevel

D 0.125 0.167 0.167 0.125 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.188 0.271 0.167 0.208 0.167 0.208 0.167 0.333 0.167 0.208 0.167 0.271 0.208 0.271 0.167 0.167 0.167 0.188 0.188 0.208 0.208 0.292 0.297 0.167 0.057 0.072* 0.125* 0.167*

Height of Ring

H 0.750 1.000 1.000 0.750 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.125 1.625 1.000 1.250 1.000 1.250 1.000 2.000 1.000 1.250 1.000 1.625 1.250 1.625 1.000 1.000 1.000 1.125 1.125 1.250 1.250 1.750 1.781 1.000 0.445 0.437 0.750 1.000

Radius in Ring

R 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.09 0.06 0.06 0.06 0.06 0.06 0.09 0.06 0.06 0.06 0.09 0.06 0.09 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.09 0.09 0.06 0.02** 0.02** 0.03** 0.06**

Depth of Groove

Width of Groove

Radius in Groove

Approx. Distance between made up Flanges

E

F

R

S

0.25 0.31 0.31 0.25 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.38 0.50 0.31 0.44 0.31 0.44 0.31 0.63 0.31 0.44 0.31 0.50 0.38 0.50 0.31 0.31 0.38 0.44 0.44 0.50 0.50 0.56 0.69 0.31 0.16 0.16 0.25 0.31

0.344 0.469 0.469 0.344 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.469 0.531 0.781 0.469 0.656 0.469 0.656 0.469 1.063 0.469 0.656 0.469 0.781 0.531 0.781 0.469 0.469 0.531 0.656 0.656 0.781 0.781 0.906 1.313 0.469 0.219 0.219 0.375 0.469

0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.06 0.06 0.03 0.06 0.03 0.06 0.03 0.09 0.03 0.06 0.03 0.06 0.06 0.06 0.03 0.03 0.06 0.06 0.06 0.06 0.06 0.06 0.09 0.03 0.03 0.02 0.03 0.03

0.38 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.91 0.47 0.47 0.47 0.47 0.47 0.84 0.47 0.47 0.47 0.72 0.59 0.72 0.47 0.47 0.38 0.38 0.38 0.38 0.38 0.72 0.75 0.47 -

* Tolerance on these dimensions is +0 -0.015 ** Tolerance on these dimensions is +0.02 -0

Table H.6 - API Type ‘RX’ Pressure Energised Ring Gaskets

H-12


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A C D E F G

(WIDTH OF RING) (WIDTH OF FLAT) (DEPTH SIZE) (DEPTH OF GROOVE) (WIDTH OF GROOVE) (OD OF GROOVE)

+/-0.008 +/-0.06-0.000 NONE +/-0.02,-0 +/-0.008 +/-0.004 - 0.

H˚ R1 R2

(HEIGHT OF RING) (RADIUS IN RINGS) (RADIUS IN GROOVE)

+/-0.008-0.000 +/-0.02 SEE NOTE

23˚

(ANGLE)

+/- 1/4 DEG

* A PLUS TOLERANCE OF 0.008 INS FOR WIDTH A AND HEIGHT H IS PERMITTED PROVIDED THE VARIATION IN WIDTH OR HEIGHT OF ANY RING DOES NOT EXCEED 0.004 INS THROUGHOUT ITS ENTIRE CIRCUMFERENCE

Figure H.6 - API Type BX Pressure Energised Ring Gaskets

NOTE: Radius ‘R’ shall be 8-12% of the gasket height ‘H’.


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H-14

111/16 1113/16 21/16 29/16 31/16 41/16 71/16 9 11 135/8 135/8 165/8 165/8 183/4 183/4 211/4 211/4 263/4 263/4 51/8 9 11 135/8

BX 150 BX 151 BX 152 BX 153 BX 154 BX 155 BX 156 BX 157 BX 158 BX 159 BX 160 BX 161 BX 162 BX 163 BX 164 BX 165 BX 166 BX 167 BX 168 BX 169 BX 170 BX 171 BX 172

0.366 0.379 0.403 0.448 0.448 0.560 0.733 0.826 0.911 1.012 0.541 0.638 0.560 0.684 0.968 0.728 1.029 0.516 0.632 0.509 0.560 0.560 0.560

2.790 2.954 3.277 3.910 4.531 5.746 9.263 11.476 13.731 16.657 15.717 19.191 18.641 21.728 22.295 24.417 25.020 29.896 29.928 6.743 8.505 10.450 13.034

ODT

Dia of Flat

0.314 0.325 0.346 0.385 0.419 0.481 0.629 0.709 0.782 0.869 0.408 0.482 0.481 0.516 0.800 0.550 0.851 0.316 0.432 0.421 0.481 0.481 0.481

C

Width of Flat

0.06 0.06 0.06 0.06 0.06 0.06 0.12 0.12 0.12 0.12 0.12 0.12 0.06 0.12 0.12 0.12 0.12 0.06 0.06 0.06 0.06 0.06 0.06

D

Hole Size

Table H.7 - API Type ‘BX’ Pressure Energised Ring Gaskets

0.366 0.379 0.403 0.448 0.448 0.560 0.733 0.826 0.911 1.012 0.938 1.105 0.560 1.185 1.185 1.261 1.261 1.412 1.412 0.624 0.560 0.560 0.560

A

H

OD

2.842 3.008 3.334 3.974 4.600 5.825 9.367 11.593 13.860 16.800 15.850 19.347 18.720 21.896 22.463 24.595 25.198 29.696 30.198 6.831 8.584 10.529 13.113

Width of Ring

Height of Ring

0.22 0.22 0.23 0.27 0.30 0.44 0.33 0.50 0.56 0.62 0.67 0.56 0.33 0.72 0.72 0.75 0.75 0.84 0.84 0.38 0.33 0.33 0.33

E

Depth of Groove

2.893 3.062 3.395 4.046 4.685 5.930 9.521 11.774 14.064 17.033 16.063 19.604 18.832 22.185 22.752 24.904 25.507 30.249 30.48 16.955 8.696 10.641 13.225

G

Outside Dia. of Groove

0.450 0.466 0.498 0.554 0.606 0.698 0.921 1.039 1.149 1.279 0.786 0.930 0.750 1.006 1.290 1.071 1.373 0.902 1.018 0.666 0.705 0.705 0.705

N

Width of Groove

C

TROL TRAININ

Outside Dia. of Ring

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Nominal Size

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HYDRATES FORMATION & PREVENTION

I.1

FORMATION OF HYDRATES

I.2

HYDRATE PREDICTION

I.3

HYDRATE PREVENTION

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APPENDIX I

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I. APPENDIX - HYDRATE FORMATION & PREVENTION I.1 FORMATION OF HYDRATES Hydrates will only form if there is free water present in a system. Hydrates are crystalline water structures filled with small molecules. In oil / gas systems they will occur when light hydrocarbons (or carbon dioxide) are mixed with water at the correct temperature and pressure conditions. A very open, cage-like structure of water molecules is the backbone of hydrates.This structure which bears some resemblance to a steel lattice in a building can theoretically be formed in ice, liquid water, and water vapour. In practice however, hydrates are only formed in the presence of liquid water.The crystal framework is very weak and collapses soon if not supported by molecules filling the cavities in the structures. Methane, Ethane, CO2 and H2S are the most suitable molecules to fill cavities. Propane and Isobutane can only fill the larger cavities. Normal butane and heavier Hydrocarbons are too big and tend to inhibit hydrate formation. Tests indicate that Hydrate formation is comparable with normal crystallisation.‘Undercooling’ is possible, but the slightest movement within and undercooled mixture, or the presence of a few crystallisation nuclei will cause a massive reaction. Once the crystallisation has started, hydrates may block a flowline completely within seconds. The formation of hydrates is governed by the crude composition, water composition, temperature and pressure. In most cases the crude composition cannot be changed. Hydrates can be dissolved / prevented by a temperature increase or a pressure decrease. A chemical hydrate inhibition can be performed by changing the composition of the water. Under the correct conditions of temperature and pressure, hydrates will form spontaneously. At high pressures, hydrates may form at relatively high temperatures; e.g. at 2900 psi they can begin to form at about 77˚ F . Hydrates do not require a pressure drop to form. However, the refrigeration effect from a small pressure drop, such as a stuffing box leak, may be sufficient to produce optimum pressure and temperature conditions for hydrate formation. Hydrates can form under flowing or static conditions.The first indication of them forming in the tubing or annular flow string is a drop in flowing wellhead pressure followed by an initially slow then progressively rapid drop in wellhead flowing temperature. During well operations, the greatest danger posed by hydrates is the plugging of the tubing string downhole. The biggest risk area for this occurring is on offshore installations from the seabed upwards where temperatures are generally the lowest. A hydrate plug in the tubing string under flowing or static conditions results in; being unable to run or pull wireline tools, unable to squeeze or circulate the well dead, and unable to flow the well to remove the hydrates. Also, hydrates may prevent vital equipment, such as the Downhole Safety Valve from functioning correctly. Thus a downhole hydrate plug gives rise to a potentially dangerous situation and must be avoided at all costs. It is also hazardous when it forms in surface pressure control equipment preventing operation of valves, etc or plugging lubricators or risers. The latter may fool an operator into believing that the pressure has been bled off when may be trapped behind the plug.


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I.2 HYDRATE PREDICTION Hydrate pressure / temperature formation conditions can be predicted for natural gas (Figure I.1). Hydrate prevention is normally accomplished by the injection of methanol or glycol downhole or at the Xmas Tree. The quantity of glycol or methanol required to suppress hydrates depends on pressure, temperature, water cut and flowrate. For the prevention of hydrates caused by the introduction of water whilst pressure testing for wireline entry, 60% glycol will have to be added to the water for use as a hydrate suppresser (See Table I.1, on freezing points of water/glycol mixes).

Glycol / Water (% v/v)

Freezing Point (deg C)

SG

100/0

-7

1.115

90/10

-28

1.109

80/20

-43

1.101

70/30

-60

1.091

60/40

-60

1.079

50/50

-44

1.068

Table I.1 - Freezing Points Of Mono-Ethylene Glycol/Water Mixes

After the glycol/water has been thoroughly mixed, no separation of the solution will occur. The glycol/water solution can therefore be left in the pump unit for the duration of the programme without the solution deteriorating. Mono-ethylene glycol may be mixed with fresh water or sea water without any adverse effect, although sea water id preferred as it in itself is less likely to cause a hydrate than fresh water. NOTE: Incorrect mixes will significantly reduce the level of protection. Although methanol is a more effective hydrate inhibitor than Glycol, it is not, however a first choice for injection at the wireline lubricator or flowhead during well operations as it dissolves sealing greases and may cause loss of seal in grease head. Also injecting glycol without any form of atomisation may result in the glycol adhering to the wall of the tubing/lubricator, and will not effectively absorb free water being lifted through gas by the wireline.

I-2


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TEMPERATURE AT WHICH GAS HYDRATES WILL FREEZE ( From KAZT )

The purpose of this chart is to determine the temperature below which hydrates will form when sufficient liquid water is present.

4000

3000

E

AN

H ET

M

600 500 400

V RA

300 6

0.

200

G

7

0 0 0.9 .8

0.

1.

PRESSURE FOR HYDRATE FORMATION PSIA

2000

1000 900 800 700

100 90 80 70 60 35

40

45

50

55

60

65

70

75

80

85

TEMPERATURE ˚F

Example : with 0.7 specific gravity gas at 1000 psia, hydrates may be expected at 64˚F at 200 psia. This would be 44˚F. Figure I.1 - Temperatures at Which Gas Hydrates Will Freeze


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I.3 HYDRATE PREVENTION Present techniques for prevention of hydrates are mainly geared to a live well with a gas cap in the tubing. This allows methanol introduced at the Xmas Tree to gravitate down to the hydrate level, and therefore act directly on top of a hydrate, should it occur. Consideration must be given to a perforated well which has not yet been “cleaned up” as gas will migrate throughout the tubing during the completion of perforation activities. To minimise the risk of hydrate formation in the well bore and surface equipment, the following action points must be taken:• 1. The fluids used for well operations should be incapable of supporting a hydrate. For example, water free base oil, diesel or water glycol mixes may be selected. • 2. Prior to opening a well flow, methanol injection must be started at maximum rate and continued until the flowline temperature is high enough to prevent hydrate formation at that FTHP (see Fig I.2) • 3. Use only a 60/40 mono-ethylene/sea water mix when pressure testing • 4. Inject glycol at the grease injection head during wireline operations. Continually inject methanol at the Xmas Tree during all well operations. Curing Hydrates The main guidance for removal of a hydrate plug is to reduce the pressure or increase the temperature, or use methanol, or any combination of these. WARNING:- IT IS HAZARDOUS TO BLEED DOWN PRESSURE ON ONLY ONE SIDE OF A HYDRATE PLUG IN ANY PIPEWORK. NOTE:- The risk is that if pressure is bled down from one side of a hydrate it will begin to dissolve. As it dissolves, differential pressure can act upon one side of the plug and may cause it to be dislodged at considerable velocity. Bleeding down can be effective in dissolving a hydrate, but it is not recommended as a routine practice. However, once a full column of fluid (preferably methanol) has been established above the hydrate plug then bleeding down the pressure above to destroy the hydrate can be considered.The full column of liquid will act as a cushion and prevent the dissolved plug achieving high velocities caused by the differential pressure across it. Curing a hydrate problem in particular sections of the system has been accomplished by the following measures:(1) (2) (3)

I-4

Plug in at the surface:Close in the well and depressurise the line, or apply steam or hot water externally. Hydrate at the stuffing box during wireline operations:Close BOP’s and bleed down the lubricator Hydrate in the tubing:Continue injecting methanol at maximum rate taking note of the THP at all times as this could begin to rise with the fluid injection.


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If during injection of methanol no increase in THP is observed (this will indicate that the tubing is not completely blocked) then begin to bleed down the tubing taking careful note of the volume and type of returns. If during injection of methanol an increase in THP is observed (this will indicate that the tubing is blocked) then only bleed down the THP to point below bubble point so as to create a gas cap above the hydrate. Methanol injected will then stand a better chance of reaching the hydrate.


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