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Unit P-02

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Drilling and Subsurface Equipment - Unit P-02

UNIT P-02

DRILLING AND SUBSURFACE EQUIPMENT

1.0 OBJECTIVES/ INTRODUCTION..........................................................................3

2.0 DRILLING TERMS AND EQUIPMENT................................................5

2.1.1 Derrick........................................................................................................5

2.1.2 Traveling Block and Crown Block................................................................5

2.1.3 Standpipe, Rotary Swivel and Flexible Hose...............................................5

2.1.4 The Drill String............................................................................................6

2.1.5 Kelly............................................................................................................7

2.1.6 Draw Works................................................................................................8

2.1.7 Rotary Table...............................................................................................8

2.1.8 Mud System................................................................................................8

2.1.9 Power Unit................................................................................................10

2.1.10 Drilling Bit..............................................................................................10

2.1.11 Drilling Operations.................................................................................10

2.1.12 Directional Drilling.................................................................................12

3.0 CASING SYSTEM.........................................................................13

3.1 Types of Casing/Tubing..............................................................13

3.1.1 Surface Casing..........................................................................................13

3.1.2 Production Casing.....................................................................................13

3.1.3 Production Tubing.....................................................................................13

3.1.4 Protective Casing......................................................................................13

4.0 BLOWOUT CONTROL SYSTEM......................................................16

5.0 PRODUCTION WELL COMPLETION................................................21

5.1.1 Open Hole Completion..............................................................................21

5.1.2 Liner Completion......................................................................................21

6.0 TUBING.....................................................................................24

6.1.2 Packer Applications..................................................................................27

7.0 WELLHEAD................................................................................30

8.0 TUBING HANGER........................................................................32

9.0 CHRISTMAS TREE.......................................................................33

10.0 PERFORATING............................................................................36

11.0 WELL CONTROL SYSTEM.............................................................38

12.0 GLOSSARY....................................................................................................41

of 45 © Petrofac Training 2007

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1.0 OBJECTIVES/ INTRODUCTION

Objectives

At the end of this lesson the trainee must be able to

Identify the parts of a drilling rig and to describe their function

State methods of blowout prevention

Describe the equipment necessary for well completion.

Identify and describe the function of wellhead equipment

Describe perforating procedures

Describe the operation of well control equipment

Introduction

This module is designed as an introduction for production operators and maintenance technicians to drilling equipment, drilling terms, and wellhead operation.

Drilling rigs have a variety of shapes and sizes; whether land-based or offshore, all have the ability to move from one site to another. All operate in basically the same manner, i.e. a turntable rotates a drill fixed to the end of a tube, as the drill moves downwards, extensions are added to the tube.

The wellhead is the upward termination of the casing strings. It is assembled on top of the surface casing string and during drilling operations provides an anchor point for the BOP stack

When the well is producing oil and gas from the petroleum reservoir flow through the production tubing to the to wellhead assembly at the surface. The wellhead assembly consists of a series of valves, process indicators and in some cases a chemical injection system.

The function of the wellhead assembly to allow:

Controlled oil production.

Start-up and shutdown.

Reservoir monitoring.

Workover facilities.

This arrangement of valves, flanges and pipework is collectively called a Christmas Tree.


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The oil and gas produced from a well is transported to production facilities where it is processed into export quality products. The most common way to transfer oil and gas from the wellhead to the production facility is through pipelines. Pipeline and wellhead equipment can fail and the resulting release of hydrocarbons or damage to equipment must be prevented or minimized.

We will now continue with a more detailed description of the equipment, operation and safeguards that are in place at a typical oil and gas wellhead facility.


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2.0 DRILLING TERMS AND EQUIPMENT

Figure 2-1 shows the main parts of a typical drilling rig.

2.1.1 Derrick

This is the tower-like construction that supports the weight of the drill pipe as it is lowered into the well. A typical modern derrick will be approximately 50 metres high, have a 10 metre square base and be capable of handling 500 + tonne loads.

The derrick is equipped with work platforms at various heights in the structure and has space for stacking up to 5000m of drill pipe.

2.1.2 Traveling Block and Crown Block

These are the pulley blocks used with a wire rope to raise and lower the drill string. The crown block is fixed to the top of the derrick and the travelling block contains the hook for lifting the swivel and kelly.

2.1.3 Standpipe, Rotary Swivel and Flexible Hose

This arrangement enables the drilling mud to be forced down the inside of the hollow drill pipe.


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Figure 2-1

2.1.4 The Drill String

Suspended from the derrick's travelling block is the swivel (see Figure 2-1). This allows the drill string to rotate whilst maintaining a fluid path for the pumping of the mud down to the bit. A sealing arrangement exists at the swivel so that no mud is lost where it enters the rotating part of the drill string.

The drill string is the name given to the complete length of drill pipe, drill bit and accessories that are lowered into the hole during the drilling operation.


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Its principal components are:

The kelly

The drill pipe

The drill collars

The subs

The drill bit

The drill string's components are connected to each other by threaded connections referred to as tool joints. Note that all joints below the bottom of the kelly have right hand threads and all those above, left hand threads (see Figure 2-2).

Each piece of steel drill pipe has a length of 28-32 feet. At the base of the drill string drill collars are located. These units have the same length as drill pipe, however, they are thicker and heavier and are used to increase the weight acting on the drill bit.

2.1.5 Kelly

This is a specially shaped length of drill pipe that fits into the rotary table and transmits the rotary movement to the drill string screwed to the drill bit.


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Figure 2-2

The kelly and its associated kelly bushing are the means by which circular motion from the rotary table is imparted to the drill string. A kelly is typically 40-42 feet long and square or hexagonal in cross section. It slides through the kelly bushing (seated in the rotary table) during drilling operations.

2.1.6 Draw Works

This is the powerful winching apparatus used to raise and lower the drill pipe string. the driller operates the draw works to raise and lower of the drill string.

2.1.7 Rotary Table

This supplies the turning movement to the drill string and occupies the space within the base of the derrick itself.

Set in the derrick floor, the rotary table supplies the turning movement to the drill string. The rotary table has a large bore, typically about 50 inches to permit different sized drill bits and other drilling equipment to be used. Bushings are inserted into the rotary table to accommodate the various equipment sizes. The rotary table may be powered by a separate D.C. electric motor or by an auxiliary drive arrangement from the drawworks.

2.1.8 Mud System

Drilling requires lubrication. The lubricant used is a mixture of water or oil and clay with other elements added such as minerals. The mud is pumped down the hole and is circulated back to the surface. It lubricates and cools the drill bits, removes chippings to the surface and holds back any subsurface pressure that the drill may encounter. The density of a given mud can be increased by the addition of barites (barium sulphate). The mud is mixed in a large open tank and pumped into the drill string via a flexible hose and swivel. Emerging at the drill bit, it carries the drill chippings upwards on the outside of the string, through the mud return line and across a screen back to the mud tanks.

At the surface a vibrating mud screen is used to remove the chippings from the circulating mud. Chippings are the only source of direct information available as to what sort of formation the drill is cutting into; samples are taken frequently for analysis. Mud pumps absorb more power than any other equipment on site.

Drilling mud has the following purposes:

It removes drill cuttings from the hole. These cuttings are sampled and subjected to analysis to yield data about the formations being drilled.

Drilling mud weight and pressure stops the inflow of fluids from any formations that are drilled. Should the well bore mud pressure be less than the formation pressure, then fluids can flow into the wellbore and force the drilling mud out of the hole. This is called a blow-out.


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The drill bit is cleaned, cooled and lubricated by the drill mud.

The contents of the mud are used in part to create a cake on the walls of the wellbore.

This helps to prevent hole collapse and also lessens the loss of drilling mud into the formations.

Figure 2-3 shows the route taken by the drilling mud during drilling operations. Mud enters the mud pump suction and is pumped under pressure through the standpipe, the rotary hose, the swivel, the kelly, the drill string down to the bit. At the bit, the drilling fluid washes the cuttings away up the annular space existing between the drill string and the wellbore wall. Mud returning to the surface is routed through the shale shaker to remove the larger drill cuttings. Finer particles are removed in cyclone separators, ready for the mud to be re-used.


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Figure 2-3


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2.1.9 Power Unit

Provides power for the rotary table, draw works and mud pumps using several large diesel units.

2.1.10 Drilling Bit

This usually consists of three equally spaced toothed wheels mounted on a head so that as the head rotates the wheels also rotate against the rock, each tooth chipping away a small piece of rock. The drill pipe immediately above the drill bit is much heavier than normal drill pipe and is referred to as a drill collar. The drill collar is heavy enough to force the teeth of the drill into the rock. As drilling proceeds, more lengths of drill pipe are added under the kelly.

The drill bit is located at the very bottom of the drill string. There are many types and sizes of drill bits. The correct one for a particular application depends on the type of formation being drilled and the hole size required.

2.1.11 Drilling Operations

Whilst drilling a well there are several important procedures which have to be performed. These include "making a connection" and "making a trip".

2.1.11.1 Making a Connection (Ref Figure 2-4)

The procedure that is performed to lengthen the drill string as drilling goes deeper is known as "making a connection". This entails:

Placing a new section of drill pipe in the mousehole.

Stopping mud circulation, raising the kelly and hanging off the drill string by means of slips at the rotary, disconnecting the kelly from the drill string and connecting it to the new piece of drill pipe waiting in the mousehole.

Reconnecting the kelly and new pipe to the drill string.

Removing the slips and recommencing drilling.

2.1.11.2 Making a Trip

During drilling it is necessary to remove the drill string from the hole. The reasons for this include:

Drill bit renewal

The running of well logging tools (e.g. devices used to determine bottom hole position)

Casing emplacement.


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Drill string retrieval constitutes "making a trip". This is carried out in the following

way:

Stop mud circulation, raise kelly and insert slips to support drill string, disconnect kelly and stand back in rat hole, attach drill pipe elevators to travelling block.

Using the drill pipe elevators the drill string is raised out of the hole. Usually three lengths of drill pipe (a stand) can be raised clear of the rotary table. The slips are reset and the pipe unscrewed from the rest of the drill string.

The pipe is placed in a rack and the procedure repeated until all the drill pipe has been retrieved from the hole. As soon as the necessary work has been performed on the well or the drill bit has been changed the drill pipe can be run back into the hole employing the reverse procedure to that outlined.

Figure 2-4


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2.1.12 Directional Drilling

Despite the problems of unwanted hole deviation, there are many instances where we do require to intentionally deviate the well. A typical case is an offshore platform where by using deviated wells it is possible to reach more of the reservoir and as a consequence drain more of the field. There are practical limits to how much a well may be deviated. Although there have recently been wells drilled with horizontal sections, considerations such as wireline techniques normally limit the maximum deviation to 60-65 degrees from the vertical.

Directional drilling can be achieved in many ways by the use of specialised tools. "Whipstocks" and "jet bits" have been used on many wells, but today probably the most common method is the down hole motor and bent sub. The downhole motor is a turbine, actuated by the flow of the drilling mud passing through it. As it turns, it rotates the bit, without rotating the drill pipe. This permits orientation of the bent sub to provide deflection in the desired direction. This method can be used in all types of formations, and continuous build up of angle can be achieved.


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3.0 CASING SYSTEM

Casing is the term given to the large steel tubes used to line the well and prevent the hole collapsing or fracturing under the pressure of the drilling fluids. Upon completion of a production well a smaller diameter steel tube is run into the well inside the casing to allow oil or gas production through. This is known as production tubing.

The design of the casing system is very important, the objective being to provide adequate protection for the well's reserves at minimum cost. The potential cost reduction through proper design of casing is high since casing is expensive, typically representing 35% of well costs. Careful tailoring of the design to the requirements can appreciably reduce costs without adding to risk and jeopardizing the well's reserves.

3.1 Types of Casing/Tubing

3.1.1 Surface Casing

The next string is the surface casing. This string varies in depth from a few hundred feet to as much as 4500 feet. Its purpose is to provide a sound foundation (if not provided by the conductor pipe) and structural support for the well, protecting fresh water sands from contamination. Diameters of surface casing vary from 7 to 16 inches (10 3/4 and 13 3/8 inch are most commonly used). This string is cemented to the surface.

3.1.2 Production Casing

Once the surface string has been installed, drilling proceeds without need of further casing so long as normal mud weights can be used (up to 12 to 13 ppg). Wells completed in this interval are cased with production casing, and drilling ceases. Production strings vary from 2 3/8 to 9 5/8 inches and extend to or through the producing formation. These strings are cemented to an adequate height above the producing formation.

The production string is run when the well has been drilled to its predetermined depth and formation tests have shown it to be economically viable.

3.1.3 Production Tubing

Tubing is installed to allow production through a removable tube to protect the casing, from erosion and corrosion damage. The tubing is suspended from the wellhead, tubing size depends on production rate, pressure and constituants of the well fluid.

3.1.4 Protective Casing

If abnormal pressures are encountered necessitating high weight mud to control the well, a protective string must be installed to prevent losing returns to more shallow


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formations. These strings vary from 7000 feet to as much as 15 000 feet in length and are usually large diameter, 7 to 113/4 inches. Larger pipe facilitates drilling rates and cuts drilling costs, but the larger pipe is more costly, an economic balance always arises. Normally only the lower 1000 feet of the string is cemented, the string hanging in the surface casing. High cement columns are sometimes used to preclude buckling.

The number of casing strings run in a well will depend on the depth. Generally the deeper the well the greater the number of casing strings employed.

A typical casing programme for a 45 degree 9,500 ft Claymore well is shown in Table 1 below.

TABLE 1- TYPICAL CASING PROGRAMME

CASING

STRING

HOLE SIZE CASING

SIZE

STEEL

GRADE

CASING DEPTH

MDRKB

Surface 26" 20" 1,000

Intermediate 17.2" 13 3/8"

72 LB/FT

N 80 6,500

Production 12.4" 9 5/8"

53.5 LB/FT

N 80 13,000

Liner 8.2" 7" 32 LB/FT N 80 13,500 (9,500 TV)

Note: When measuring depths in a well the datum used is always the drill floor of the rig that drilled the well. Hence the following measurements:

TVBDF TVRKB - True vertical depth measured from the drill floor (kelly bushing)

MDBDF MDRKB - Measured depth from the kelly bushing (i.e. along hole)

The casing placed in the well is cemented in place. Oilfield cements differ from concrete used in construction projects in that they contain no coarse sand or gravel. Water is added to the cement to form slurry which can be pumped downhole to cement the casing to the wellbore.

The main functions of the cement around the casing are to:-

Structurally support and restrain the casing.

Seal the annulus between the casings and prevent fluid movement between zones.

Provide well control by weight and rapid curing after protective drilling mud is displaced.

Protect the casing's exterior surface from potentially corrosive fluids.


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Protect intermediate casing strings from the effects of torque and shock loads when drilling deeper.


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Figure 3-1

4.0 BLOWOUT CONTROL SYSTEM

This system consists of the mud, the blowout preventer, the kill line, the choke line, and the choke manifold.

Blowout can occur when the hydrostatic pressure of the mud in the hole falls below the pressure of fluid, either water, oil, or gas, in a formation that has been drilled into. The first indication of pressure imbalance occurs when the mud begins to be pushed out of the well. If all the mud is pushed out, a blowout is said to have occurred and control to the well is lost.

The mud column is the primary control against blowouts. It should always exert sufficient pressure to prevent formation fluid from flowing into the well. If primary control fails and a kick occurs, secondary control is provided by a Blowout Preventer Stack (BOP See Figure 4-1).

The back-up or secondary pressure control system consists of blow-out prevention equipment.

Typical equipment includes;

Annular blow-out preventers

Ram type blow-out preventers

Choke and kill manifolds

Non-return valves and kelly stop cock

The BOP prevents blowouts by closing across the top of the well, whether the drill string is in the well or not. The BOP stack is situated below the rig floor and is connected to the wellhead by wellhead flanges.

There are two basic types of blowout prevention mechanisms in the stack: the annular and the ram (see Figure 4-1). The annular blowout preventer, a rubber ring mounted at the top of the stack, which seals with the drillpipe or irregular shaped objects in the hole, is also known as a bag preventer. The preventer is actuated by hydraulic fluid which moves a tapered piston upwards. The piston then forces the rubber sealing element to contract around the drill string.

The ram type blow-out preventer has a pair of hydraulically operated pistons or rams. The ends of the rams can be of various shapes or type, e.g.

Heads which fit directly around the drill pipe - known as pipe rams.

Heads which can cut through tubing in hole thereby creating a seal-referred to as shear rams.

Heads which can seal off an empty hole - called blind rams.


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Figure 4.1

The ram type blow-out preventer has a pair of hydraulically operated pistons or rams. The ends of the rams can be of various shapes or type, e.g.

Heads which fit directly around the drill pipe - known as pipe rams.


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Heads which can cut through tubing in hole thereby creating a seal-referred to as shear rams.

Heads which can seal off an empty hole - called blind rams.

The choke line takes the mud or invading fluid from the closed-in well to the choke manifold which controls the rate of escape of the fluid and directs it back to the mud pits or to a flare line.

There are many reasons for kicks occurring. Because of the potential danger of blowouts, great care must be taken to recognise the first signs of a kick and to control it immediately.

A hole full of mud that has the correct mud weight and density should not be blown out. Unfortunately, human errors in calculations can result in too little mud or too much water being added to the circulating system, thus decreasing hydrostatic pressure.

Other reasons for mud pressure reductions are:

When the casing has been perforated or a plug drilled out, the wellbore may be exposed to formation pressure greater than can be controlled by the column of fluid in the wellbore.

If a string is raised too fast, it can create a swabbing effect, whereby the well fluid clings to the pipe as it is brought out, thereby decreasing the volume of mud in the wellbore.

Objects connected to the drill string or tubing, such as packers and testers, act as pistons and increase pressure differential between the formation fluids and the drilling mud.

When a potential blowout is detected, mud is pumped down the drill pipe (or the kill line, if no drill pipe is in the hole) to restore pressure balance in the hole. When excess gases occur, the bag and ram type BOPs are closed around the drill string. The gas pressure is released at the choke manifold by slowly opening the choke, displacing mud as the bubble or gas entrapped mud approaches the surface. Without the choke, the gas would push out the annulus mud between the drill string and the riser and control from the weighted mud would be lost. An uncontrolled blowout would result if the gas pressure at the surface were to exceed the pressure of the wellhead or the BOP.

The choke and kill lines control kicks to prevent them from developing into blowouts.


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Figure 4-2


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The choke manifold has an important function in controlling a kicking (i.e. flowing) well when the BOPs have been closed. The manifold contains various sized chokes for bleeding off and controlling high pressure well fluids. In addition to the choke system there is also the kill system. This is used to route fluid down the well thereby creating sufficient hydrostatic pressure to stop the well flowing.

Should the BOPs be closed around the drill string, it can be seen that a fluid route to surface exists through the hole in the drill pipe. This flowpath is sealed either by including a non return valve near the drill bit, or using a manually operated shut-off valve (kelly stop-cock) at drill floor level.

Figure 4-3


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5.0 PRODUCTION WELL COMPLETION

There are two basic categories of well completion:

Open hole completions

Liner completions

5.1.1 Open Hole Completion

The open hole completion method calls for production casing to be set above the zone of interest prior to drilling. The well is completed with the producing interval open to the wellbore.

Some advantages are:

Minimizes formation damage.

No perforating expenses.

Log interpretations are not critical as all the zone is open.

Full hole diameter is available at pay zone.

Can be deepened easily.

Can be converted to liner or perforation completion if necessary.

The disadvantages are:

Frequent workover (cleanout).

Difficulty in controlling excessive gas or water production.

Last casing must be set before drilling into productive zone.

Cannot be selectively stimulated.

5.1.2 Liner Completion

There are two common types of liner completions:

Wire screen and liner completions

Perforated casing completions

In wire screen and liner completions the casing is set above the producing zone and an uncemented screen and liner assembly is installed across the pay section.


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Advantage:

Adaptable to special techniques to control sand; cleanout problems can thus be avoided.


Additional rig time required.

Well cannot be easily deepened.

In perforated liner completions, casing is set above the producing zone, the pay is drilled, and a liner casing is cemented in place. The liner is then selectively perforated for production. The perforating procedure is described in the next section

The advantage over the screen method is:

Well can be easily deepened.


Extra cost and rig time for perforating.

Log interpretation to select zones for perforation becomes very important.

In a perforated completion, such as illustrated in Figure 5-1, some of the

advantages are:

Control of gas or water production.

Selective stimulation.

Multiple production techniques possible.

Easily deepened.


High cost of perforating.

Interpretation of logs is critical (to avoid missing commercial sands and so avoid perforating non-productive areas).


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Figure 5-1


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6.0 TUBING

Wells can be produced with or without tubing. Those that do not use small diameter pipe inside the production string are described as tubingless completions, oil or gas simply rises up the production string (with or without artificial means) to the wellhead. This type of completion is simple and cheap to produce.

Tubing inside the production string offers many advantages over tubingless completions:

Circulation of kill fluids, corrosion inhibitors or paraffin solvents.

Multiple flow systems with artificial lift.

Protection of casing from corrosion, abrasion and pressure.

A tubing completion entails the placing of one or more, smaller diameter tubes inside the production casing, the tubing is suspended from the wellhead and can be removed if necessary.

Single completion (see Figure 6-1) produces from a single zone or formation. Dual completion (the most common type of completion), produces from two different zones or formations up to the surface through separate pipes.


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Figure 6-1


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In the case of a dual tubing string (two independent sets of production tubing) the wellhead will have a double Christmas tree. The production strings are set at different depths or zones within the formation. Each production zone will produce oil or gas through its own production string. The strings are described as Upper (U) and Lower (L) production strings, in some installations the terms Long (L) and Short (S) are used.

Whichever completion is used the tubing must not only withstand the same types of stresses that casing experiences but must also resist the corrosivity of well fluids. In addition tubing joints must be very strong to resist leakage into the annulus. Because of this the oil industry has developed over the years special joints, which are referred to as premium connections. One such connection is the Hydril TAC-1-CB joint shown in Figure 6-2.

The thread profile is a modified buttress thread and is arranged as two parallel threads for ease of make up. At the leading edge of the pin is a metal to metal seal with a re-entrant shoulder at the base of the pin to withstand the high torques needed to activate it.

Figure 6-2


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Also included in the joint is a seal ring (called a corrosion barrier). This combined with the plastic coating on the inside of the tubing provides a smooth lining to the w ell bore. This reduces the resistance of the tubing to flow as well as providing barrier for corrosion.

6.1.1 Packers (See Figure 6-3)

This is a piece of downhole equipment consisting of a sealing device, a holding or setting device, and an inside passage for fluids. It blocks the flow of fluids through the annular space between the tubing and the wall of the wellbore by sealing off the space between them. It is usually made up in the tubing string above the producing zone. A sealing element expands to prevent fluid flow into the annulus between the production tubing and production casing. Packers are classified according to configuration, use, method of setting and whether or not they are retrievable.


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Figure 6-3

6.1.2 Packer Applications

Packers are used in the following applications:

Casing protection.

Separation of multiple zones.

Isolation packers.

Artificial lift; gas lift.

For a packer to perform its function a cone is driven behind a tapered slip to expand the slip and fill the space between the tubing and casing wall; the sealing element is compressed to form a seal against the casing wall. The two most important basic components of packer construction are the slips and the sealing element.

Packer slips can be unidirectional, or be designed to resist force from either direction.

Sealing elements may be of either one piece construction, or composed of multiple elements of different degrees of hardness.

Mechanical or hydraulic means are used to drive the cone behind the slips to firmly locate the packer against the wellbore.

Figure 6-4 illustrates the Baker SABL permanent packer. The driving force for setting the packer is generated by hydraulic pressure acting on the annular setting piston at the bottom of the packer. As the pressure increases the shear pin between the piston and the packer body is broken and the piston moves upwards setting and anchoring the packer firmly into the casing.

A rubber sealing element is compressed between the cones located above and below it, and creates the seal. The cones are locked into position by opposing slips which prevent any movement of the packer. Expanding metal rings contain the rubber sealing element and prevent extrusion which could ruin the sealing arrangement.


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Figure 6-4


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Unlike the permanent packers a retrievable packer can be unset and released from the casing allowing it to be recovered. The retrievable packer used was a Camco HRP-1-SP shown in Figure 6-5. It is a hydraulic set packer and in essence the setting mechanism is similar to that of the Baker SABL, except that it is a single bi-directional slip supported and anchored in place by the cones.

To release the packer a straight overpull is applied. This breaks the primary shear pins within the release housing and allows the upper sections of the packer to move upwards. As this happens equalising ports in the body are exposed and equalisation between the tubing and annulus occurs. Continued upward movement releases the ratchets and allows the sealing element to relax and the slips to retract. The packer is now free and can be removed from the tubing.

Figure 6-5


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7.0 WELLHEAD

The normal method of attaching casings to the wellhead is to use hanger mandrels screwed to the top of the casing string. A seal assembly is installed (and tested) to close off the annulus created on the outside of the casing.

The wellhead is built up whilst the well is being drilled, see Figure 7-1. The first casing is installed and cemented in place. At the surface a casing head is assembled on top of this casing and a BOP stack is installed. The drilling operation is continued and eventually a second casing is run and landed inside the casing head housing and hung off in the internal taper using a mandrel or a slip and seal assembly, prior to being cemented.

The next casing head can then be positioned and the above procedure repeated. When all the casing has been positioned and cemented in the well the production tubing string can be installed.

Access into each annulus is provided by side entry nozzles through the wellhead, these are then protected by valves and blind flanges to give a double level of protection.

All potential leak paths from each casing annulus are protected by two independent barriers. In the case of the production annulus which will be used for gas lift, these valves will, of course, need to be left open. To provide a level of safety a flapper type check valve is installed in both side outlets of the wellhead. In the event of any problem this will close and prevent the backflow of gas and well fluids.


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Figure 7-1


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8.0 TUBING HANGER

In principle the tubing hanger mandrel is the same as the casing hangers described above. It screws onto the tubing and locates on a tapered shoulder at the top of the wellhead spool. It supports and provides the main anchor point for the tubing which hangs in tension from here down to the packer. (Depending on the particular well design some of the tubing weight may be supported by the packer). The tubing hanger also seals the annulus and is provided with a bored hole to allow the entry of the control line for the SSSV see figure 8-1.

Inside the tubing hanger bore a special lock and sealing profile is machined into which can be set a Back Pressure Valve, used to seal the tubing and to provide the necessary well control during installation or removal of the Christmas tree.

Figure 8-1


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9.0 CHRISTMAS TREE

The Christmas tree locates on top of the wellhead and provides a number of valves that control and isolate the well. Christmas trees are rated for maximum working pressure. A typical Single string Christmas tree is shown in Figure 9-1 and a Dual string Christmas tree in Figure 9-2.

Oil flow is via the;

Lower master valve.

A manually operated valve which is not used for day to day control of the well. This valve is only used in the event of leakage or failure of other valves on the tree.

Master Valve (or Upper Master Valve).

This is the Surface Safety Valve and is a reverse acting valve operated by a hydraulic actuator controlled from the well control panel. It is also linked to the platform emergency shutdown system and it will automatically close and secure the well in the event of a hazardous situation developing.

Flow Wing Valve.

Also a reverse acting valve operated by a pneumatic actuator controlled from the well control panel, and linked into the ESD system.


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Figure 9-1


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Figure 9.2

On some wellhead installations a second flow wing valve located immediately upstream of the actuated valve. This is a manually operated valve and was provided as a back-up to the pneumatic valve.

In addition there are two further manually operated valves - the kill wing valve and the swab valve. The kill wing is used to pump kill fluid (i.e. weighted fluid) downhole when preparing for a workover and is also used for many of the chemical treatments used in the well and reservoir adjacent to the well bore (e.g. acidisation, scale inhibition). The swab valve is the valve at the top of the Christmas tree and is used to gain vertical access to the well for wireline work.

In the two actuated valves are 'reverse acting' i.e. the gate and stem move into the valve to open it and out of the valve to close it. The advantage of this design is that should the spring of the actuator break the valve can still close due to the well pressure acting on the stem cross sectional area.

When operating the valves on the Christmas tree care should always be taken to protect them from wear. When shutting a well in, the choke should be closed first, followed by the wing and then the master valve. When opening a well up, the reverse order should be followed. To minimise wear and the maintenance none of the Christmas tree valves should ever be left in a partially open condition. For the same reason the operator must ensure that the upper master valve is never operated when the well flowing. The lower master valve is not utilised at all during normal operations but is kept in reserve and only closed in an emergency.

During wireline operations the lubricator is attached to the tree cap, and the swab valve used to isolate it from well pressure while inserting or removing wireline tools. Never close the swab valve without confirming with the wireline operator that it is safe to do so. If the wireline is in the well the valve will cut it in two and a time consuming fishing operation will result.


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10.0 PERFORATING

The process of perforating is performed in order to establish a flow route between the hydrocarbon bearing formation(s) and the cased well. On a new well, perforating is normally done after the well has been completed and the Christmas tree installed. The device most commonly used to establish this communication is the jet perforator which utilises shaped explosive charges developed from the principles of armour plate penetrating projectiles (e.g. the bazooka).

As shown in Figure 10-1, there are three explosive parts in the shaped charge. The primacord is fired electrically from the surface and detonates the primer, which in turn causes the main charge to explode. The explosion of the main charge collapses the liner and causes intense pressure which splits the liner into two distinct parts. A high velocity jet of fine particles which perforates the casing and the formation is followed by a slower moving slug of debris.

Figure 10-1


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Figure 10-2 depicts in cross section a typical retrievable jet perforator. These types of guns are usually designed for four shots/foot with all the shots in a vertical line or phased at 90 or 120 degrees but can be loaded at any shot density required.

Other types of perforating gun (e.g. expendable guns or tubing conveyed guns) are available and are used in wells where the internal diameter of the tubing limits the size of gun that can be passed. Tubing conveyed guns are gaining in popularity as the charge they can carry is larger than the thru-tubing guns and consequently larger perforations can be created. Alternatively the shot density can be increased and more perforations per foot (up to 16 shots/foot) created to improve the efficiency of the flow.

Figure 10-2


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11.0 WELL CONTROL SYSTEM

Hydraulic control fluid is supplied at high pressure (approx. 200 barg) to the master and downhole valves of each platform Christmas tree from a bulk storage system via a pump skid and the well control panels. One type of hydraulic control fluid is a water based consisting of 55% water, 40% glycol, and 5% other chemicals.

Instrument air is filtered and regulated and supplied to each of the well control panels. Within each panel (controlling one or more wells) the air supply is split into manifolds that supply operating air for wing valve, master valve and SCSSV. Pilot valves are also fitted in the operating air supply lines to these valves. The pilot valves are operated from the ESD system to provide the necessary ESD shutdown functions.

Figure 11-1


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The operating air from each manifold is manually controlled by 'palm push' buttons on the well control panel located near the wellhead, see Figure 11-1, on the front of the panel, pneumatic/hydraulic interface valves control the hydraulic fluid to the valves. These 'palm push' buttons (pull to open - push to close) are self latching and interlinked. The interlink system closes the valves in a safe order sequence e.g. manually closing master valve will trip the wing valve, and closing the SCSSV will trip both the master and wing valves. In the SCSSV air line, between the palm push button and the interface valve, is a check valve and choke arrangement to provide a time delay between commanding the valve closed and the closing operation. This is to ensure closure of the tree valves occurs first to protect the subsurface valve. When the palm push button is operated the subsurface valve should be closed within a preset time (one or two minutes usually).

Fitted to the flow line between wing valve and choke are high and low pressure pilots. In the event of flowline pressure falling outside this range one of the pilots will trip and close the pneumatic wing valve. Above the palm push buttons at the well control panel is a service/by-pass switch to enable this function to be by-passed during testing of the pilots or start-up after a total showdown.

At the wellhead/Christmas tree there are a number of valves on both the master valve and SCSSV hydraulic supply lines, as shown in Figures 11-2. For the SCSSV these consist of isolation valves, vent valve, pressure gauge and a connection point for the wireline control unit used to control the valve during wireline work. For the master valve the arrangement is similar but with the addition of a quick release valve which speeds up the closure of the master valve by dumping hydraulic fluid on sensing a pressure drop in the hydraulic line.


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Figure 11-2


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12.0 GLOSSARY

To assist the reader and to act as an easy reference, some of the words and expressions used in this handout are explained below:

Braided line A multistrand wire line used for fishing or other specialised

work.

B S & W Basic Sediment and Water.

Bubble point The pressure at which the first gas is liberated from the liquid

as the pressure is reduced.

Centralisers Mechanical devices for holding the drill pipe (or other

equipment) central in the well bore.

Conductor line A multistrand wire line containing an electrical signal wire for

use with downhole data recording instruments.

Connate water Residual water contained in the hydrocarbon bearing rock.

Core A section of rock recovered as a column from the bottom of

the well during drilling.

Drilling Subs A short length of pipe used to connect parts of the drill string

having threads of different design or size

Electrical line See conductor line.

GOR Gas Oil Ratio

Gyro survey Instrument survey of a well bore to determine the slope,

direction and position of the well bore.

Kick off point The point in the well bore below the platform where the well

is deviated away from the vertical.

MD Measured depth. The position in a well measured along the

well bore.

Mouse hole A hole in the drill floor used for standing a single length of

drill pipe in.

Mule shoe An alternative name for a Wireline Entry Guide.

Permeability A measure of the ability of fluid to pass through a rock.


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Pipe dope A lubricant used in connecting drill pipe, tubing and casing.

Pipe tally A record of the lengths of all items used in a well during

drilling or completion.

Porosity A measure of the volume of the rock pores expressed as a

ratio of the total rock volume.

Pup joint A short section of pipe.

Rat hole A hole in the drill floor used to stand the Kelly and swivel in.

Seismic survey The gathering of subsurface geophysical information by the

use of shock waves transmitted through the rock.

Shale A type of sedimentary rock composed of fine muds and clays.

Most shales are impervious and non hydrocarbon bearing.

Slick line A single strand wire line.

Slips Wedges used to support drill pipe and tubulars at the drill

floor.

Stock Tank Barrels A measure of the volume of oil converted to standard

conditions (STP).

STOIIP Stock Tank Barrels of Oil Initially In Place a measure of the

initial oil in a reservoir.

TVD True Vertical Depth.

Unconformity A geological feature caused by erosion and subsequent

deposition of sediments.

Water cut A measure of water produced as a percentage of total flow.


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