Well Intervention Presssure Control (IWCF)

CONTENTS

CONTENTS

1.

COMPLETION DESIGN

2.

BARRIERS AND CONTAINMENT DEVICES

3.

WORKOVER AND POTENTIAL HAZARDS

4.

BASIC PRINCIPLES OF HYDROSTATIC PRESSURE

5.

WELL KILL PRINCIPLES AND PROCEDURES

6.

WIRELINE PRESSURE CONTROL

7.

COILED TUBING PRESSURE CONTROL

8.

OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL

9.

FLANGED END AND OUTLET CONNECTIONS

 RIGTRAIN 2002 – Rev 1

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CONTENTS

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 RIGTRAIN 2002– Rev 1

COMPLETION DESIGN

CONTENTS

1.

COMPLETION DESIGN

1

1.1

INTRODUCTION

1

1.2

DESIGN CONSIDERATIONS

1

1.3

COMPLETION AT THE RESERVOIR 1.3.1 Open Hole (Barefoot) Completion 1.3.2 Uncemented Liner Completions 1.3.3 Cased and Cemented Completions

5 5 5 5

1.4

PERFORATING 1.4.1 Gun Types and Perforation Methods

8 10

1.5

WELL INFLOW PERFORMANCE

15

1.6

VERTICAL LIFT PERFORMANCE

19

1.7

FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING

22

1.8

COMPLETION COMPONENTS DESCRIPTIONS 1.8.1 Re-entry Guide 1.8.2 Landing Nipple 1.8.3 Tubing Protection Joint 1.8.4 Perforated Joint 1.8.5 Sliding Side Door 1.8.6 Flow Couplings 1.8.7 Side Pocket Mandrels

27 27 28 29 29 30 32 32

1.9

SAFETY VALVES 1.9.1 Types Of Sub-surface Controlled Safety Valve 1.9.2 Surface Controlled Safety Valves 1.9.3 Annulus Safety Valves (ASVs) 1.9.4 Tubing Hanger 1.9.5 Xmas Tree 1.9.6 Production Packers 1.9.7 Seal Assemblies 1.9.8 Expansion Joints 1.9.9 Tubing 1.9.10 Sub-sea Wellheads 1.9.11 Examples of Single String Completions

34 34 37 41 41 44 47 52 55 56 59 61

1.10 DUAL COMPLETIONS 1.10.1 Examples of Dual String Completions


68 68

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COMPLETION DESIGN

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COMPLETION DESIGN

1.

COMPLETION DESIGN

1.1

INTRODUCTION In simple terms, the term ‘well completion’ refers to the methods by which a newly drilled well can be finalised so that reservoir fluids can be produced to surface production facilities efficiently and safely. In general, the process of completing a well includes the following: • • • •

•

A method of providing satisfactory communication between the reservoir and the borehole The design of the tubulars (casing and tubing) which will be installed in the well An appropriate method of raising reservoir fluids to the surface The design, and the installation in the well of the various components used to allow efficient production, pressure integrity testing, emergency containment of reservoir fluids, reservoir monitoring, barrier placement, well maintenance and well kill The installation of safety devices and equipment which will automatically shut a well in the event of a disaster.

In general, a well is the communication link between the surface and the reservoir and it represents a large percentage of the expenditure in the development of an oil or gas field. It is of utmost importance that the well be ‘completed’ correctly at the onset, in order that maximum overall productivity of the field may be obtained. The ideal completion is the lowest cost completion which will meet the demands placed on it during its producing lifetime.

1.2

DESIGN CONSIDERATIONS Before a production well is drilled, a great deal of planning must be undertaken to ensure that the design of the completion is the best possible. A number of factors must be taken into consideration during this planning stage, which can broadly be split into reservoir considerations and mechanical considerations. RESERVOIR CONSIDERATIONS • • • • • • • •

Producing rate Multiple reservoirs Reservoir drive mechanism Secondary recovery requirements Stimulation Sand control Artificial lift Workover requirements.

MECHANICAL CONSIDERATIONS • • • • •

Functional requirements Operating conditions Component design Component reliability Safety.


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COMPLETION DESIGN

Figure 1 shows an example of a north sea drilling and casing schedule the main features are as follows: 1.

The installation of a 30 ins conductor to approx 500 ft. Conductor pipe provides structural strength, covers soft formations just below the sea bed and is the largest diameter pipe installed in a well. The hole required to accommodate conductor pipe can be drilled (onshore) of pile driven (offshore).

2.

The installation of 20 ins surface casing which terminates at 1,000 ft total vertical depth. Surface casing pipe provides protection against shallow gas, seals off shallow water bearing sands, and provides a base for the BOP stack and the wellhead assembly. Surface casing is always cemented back to surface.

3.

The installation of 133/8 ins intermediate casing which terminates at 4,000 ft total vertical depth. Intermediate casing pipe is used to protect weak formations; helps prevent lost circulation of drilling fluids, and hole caving. (In a deep well, more than one intermediate casing string may be set.) Intermediate casing is usually cemented to a few hundred feet above the casing shoe of the surface casing string.

4.

The installation of 95/8 ins production casing which terminates approx 7,500 ft total vertical depth. Production casing pipe is used to provide control of the completed well and is the main string that reaches down to the producing interval(s). Production casing is usually cemented to a few hundred feet above the casing shoe of the intermediate casing string.

NOTE:

Drilling operations may be resumed to deepen the well and liner casing installed and hung off from the lower end of the production casing.

A wellhead provides a means of: • • • • • •

Support for each casing string Support for the BOP equipment for the next section of hole to be drilled Sealing off the various annuli from pressure control purposes Support for the completion string Support for the Xmas Tree Control of annulus pressure.

Surface wellheads are installed in sections after each casing string is run. Each casing hanger also provides an annulus seal. Subsequent wellhead sections seal off on top of the previous casing string. Figure 2 shows a simplified schematic of surface wellhead sections. The bullets shown represent a common way of representing annuli. • • •

2

The 95/8 ins or production casing string when we insert tubing in the well this would be termed the tubing/production casing annulus The 95/8 ins and 133/8 ins annulus 133/8 ins and 20 ins annulus.


COMPLETION DESIGN

Figure 1 - North Sea Casing Profile Example


3

COMPLETION DESIGN

Figure 2 - Typical Surface Wellhead System

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COMPLETION DESIGN

1.3

COMPLETION AT THE RESERVOIR There are several methods of completing a well at the producing zone (or zones) in order to admit reservoir fluids into the borehole at the depth of the reservoir (or reservoirs).

1.3.1

Open Hole (Barefoot) Completion Production casing is set and cemented to a depth just above the producing zone. The reservoir is then drilled into and the drilled hole left as it is (Refer to Figure 3a). This type of completion is ideal where the reservoir rock is of the appropriate mechanical strength i.e. is consolidated and will not slough or cave in. Open hole completions have very little application in the North Sea where reservoirs are heterogeneous or where the development is high risk and high cost. Open hole completions offer no scope for isolating individual zones for production, stimulation or remedial work. However, this bottom hole completion type is used extensively in land fields where cost savings from not running and perforating casing significantly reduce total well costs. The advantages and disadvantages of open hole completion types are indicated in Table 1.

1.3.2

Uncemented Liner Completions In a non-consolidated formation where sand is likely to be produced, a non-cemented liner may be used. The production casing is set above the producing zone and an open hole drilled. The open hole is then lined with a short length of slotted or wire-wrapped casing (or tubing) which is hung from the production casing and sealed into it (Refer to Figure 3b). The slots or wire wrapped pipe prevents sand from entering the well bore. In sandy wells where slotted or wire wrapped liner has proved inadequate, the refinement technique of gravel packing has been developed. Gravel packing consists of filling the annular space between the open hole and the liner with a sheath of gravel - the external gravel pack. The gravel used is a coarse sand with a grain diameter appropriate for controlling unwanted sand production. Sand screens are available where the coarse sand is already pre-packed in the liner assembly. This bottom hole completion type has all the disadvantages of the open hole completion with the added cost of the liner and liner hanger thrown in. Uncemented liner applications are as for the open hole type, but where unconsolidated sands require to be controlled. The advantages and disadvantages of uncemented liner completion types are indicated in Table 1.

1.3.3

Cased and Cemented Completions This is the most common type of bottom hole completion methods especially in the north sea. In this type of completion the production casing or liner is set and cemented through and beyond the producing zone or zones. Communication with the reservoir is then established by shooting holes through the casing or liner (Refer to Figure 3c). The cement sheath around the liner/casing isolates each zone or layer of a reservoir and permits zones to be selectively perforated, produced, and stimulated. The initial cost of completing this way has higher cost implications. The advantages and disadvantages of cased and cemented completion types are indicated in Table 1.


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COMPLETION DESIGN

Bottom Hole Completion Technique

Advantages •

Open Hole

• • • •

No perforating, no production casing, no cementing expense Minimum rig time Full diameter hole in the pay zone improves productivity No critical log interpretation is required. No perforating or cementing expense for the production casing Assists in preventing sand production No critical log interpretation is required.

Disadvantages • • •

Liable to ‘sand out’ No selectivity for production or stimulation Ability to isolate is limited to the lower part of the hole.

•

No selectivity for production or stimulation • Cost of slotted liner or pre• packed screen Slotted Liner • Difficult to isolate zones for • production control • Slightly longer completion time than for open hole completion. • Introduces flexibility allowing • Requires critical log isolation of zones and selection interpretation to specify actual of zones for production or perforation zone Cased and injection. • Cost of casing/liner and Cemented cementation • Cost of rig time for longer completion period. Table 1 - Bottom Hole Completion Techniques - Advantages And Disadvantages

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COMPLETION DESIGN

Figure 3 - Methods Of Completing At The Producing Zone


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COMPLETION DESIGN

1.4

PERFORATING It will be necessary in most cases to perforate a hydrocarbon bearing zone in cased hole completions in order to realise optimum production. Some wells can flow open-hole but, where a formation is relatively unconsolidated, flow rates are expected to be high and for reasons of safety, perforated cased hole completions are usually considered preferable. Perforating is an operation whereby holes are made through the production casing (or liner) and its cement sheath into the reservoir to permit oil or gas to flow into the wellbore. Nowadays, virtually all perforating is performed with shaped charge perforators. Bullet perforators are occasionally used for particular applications. As far a completion design is concerned, the following comment cannot be overstated. ‘The fate of a well hinges on years of exploration, months of planning, and weeks of drilling. But ultimately it depends on perforating the optimal completion, which begins with the first millisecond of perforating. Profitability is strongly influenced by the critical link between the reservoir and the wellbore.’ Perforations must provide a clean flow channel between the producing formation and the wellbore with minimum damage to the producing formation. The ultimate test of the effectiveness of a perforating system, however, is the well productivity. The productivity of a perforated completion depends significantly on the geometry of the perforations. The major geometrical factors (Refer to Figure 4) that determine the efficiency of flow in a perforated completion are: • • • •

Perforation length Shot density Angular phasing Perforation diameter.

The relative importance of each of these factors on well productivity depends on the type of completion, formation characteristics, and the extent of formation damage from drilling and cementing operations. The method of perforating a well must be meticulously planned.

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COMPLETION DESIGN

Figure 4 - Perforation Geometry


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COMPLETION DESIGN

1.4.1

Gun Types and Perforation Methods There are three basic perforating gun types: • • •

Retrievable hollow carrier gun Non-Retrievable or Expendable gun Semi-Expendable gun.

Each type is available for through tubing work or as a casing gun. (Refer to Figure 5a) The retrievable hollow gun carrier consists of a steel tube into which a shaped charge is secured - the gun tube is sealed against hydrostatic pressure. The charge is surrounded by air at atmospheric pressure. When the charge fires, the explosive force slightly expand the carrier wall but the gun and the debris within the gun are fully retrieved from the well. The non-retrievable or expendable gun consists of individually sealed cases made of a frangible material e.g. aluminium, ceramic or cast iron (Refer to Figure 5b). The shaped charge is contained within the case and when detonated, blasts the case into small pieces. Debris remains in the well. With semi-expendable guns, the charges are secured on a retrievable wire carrier or metal bar (Refer to Figure 5c). This reduces the debris left in the well and generally increases the ruggedness of the gun. There are currently three standard methods of perforating a well using shaped charges: • • •

Casing gun perforating (run on wireline) Through-tubing perforating (TTP) (run on wireline) Tubing-conveyed perforating. (TCP) (Run on tubing)

Figure 6 shows schematically the application of the three main perforating techniques. TCP combines the best features of both casing guns and through-tubing guns and not surprisingly is now the most widely used perforating technique used in the North Sea. The guns are run as an integral part of a drill stem test (DST) or a completion string. The guns are fired only after a packer has been set, a surface test tree has been installed, and the entire completion string pressure integrity tested. Firing (detonation) can be achieved using annulus or tubing pressure, mechanically or electrically in which case a wireline assembly has to be run in the well. A time delay mechanism is incorporated to allow the surface tubing pressure to be bled off to give the desired over balance/under balance when the guns fire. A typical device is shown in Figure 7. The guns can be jettisoned after firing and allowed to fall to the bottom of the well below the perforated interval.

NOTE:

10

The completion requirement for a TCP system is to allow an appropriate sump for the guns to fall into.


COMPLETION DESIGN

The advantages of TCP systems are: • • • • •

Large intervals can be perforated at one time Easy to perforate in deviated wells Large gun sizes can be used with high shot densities Perforating may be carried out in under-balanced conditions Safest method to perforate.

The disadvantages are: • Entire completion string must be pulled and re-run if the guns fail • Additional hole must be drilled below the reservoir to accommodate the guns. For a TCP system, a radioactive source is incorporated in a sub in the completion string for correlating the guns. The sub can be logged with a gamma ray logging tool to determine the exact position of the guns with respect to the formation.


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COMPLETION DESIGN

Figure 5 - Perforating Gun Types

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COMPLETION DESIGN

Figure 6 - Perforating Techniques


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COMPLETION DESIGN

Figure 7 - Hydraulic Time Delay System

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COMPLETION DESIGN

1.5

WELL INFLOW PERFORMANCE The first tangible evidence of having found a hydrocarbon-bearing reservoir in an exploration well, is provided by the drill cuttings. This evidence may be backed up by core sampling and/or logging. However, the only way to find out if the hydrocarbons are recoverable is to run a drill stem test (DST), which is a means of flowing the well safely to surface to monitor the reservoir’s dynamic performance. Historically DSTs were performed using drill string, as the name implies, but nowadays most offshore DSTs are run using a specially design string with tubing as the production conduit. An example of a DST string is illustrated in Figure 8. The purpose of a DST is to obtain reservoir data necessary to plan the development of a field and to optimise recovery from a well. Such reservoir data includes: • • • •

The static reservoir pressure The composition of the produced fluids The well productivity Indications of reservoir heterogeneities or boundaries.

Knowledge of the initial static reservoir pressure is vital and must be made before it is disturbed by significant flow. It is from this reference point that comparisons and calculations are made which help to define the development of the reservoir. Also of great importance is the effect of flowing the well on its drive mechanism. Accurate well testing and analysis of results from several exploratory wells will reveal the nature and source of this drive. The Productivity Index (PI) is the starting point for examining a wells ability to deliver fluid. In Figure 9 we can see that the productivity index is 16.6 bbl/day per psi drawdown. Theoretically then, for every 1 psi the well is drawn down a further 16.6 barrels will be produced. This relationship between flowing BHP and fluid production will form a straight line on an IPR curve (Refer to Figure 10) until drawdown is sufficient to reduce the BHP below the bubble point. Knowing the PI can enable us to select a production rate at surface with a known drawdown. The production choice will be selected to ensure the well produces above the bubble point and a suitable tubing ID can be chosen to best serve the reservoir management policy. Inflow performance relates to the movement or flow of fluid from a reservoir into the bottom of the wellbore. Inflow performance response (IPR) or deliverability curves are used to evaluate and predict well performance at the exploration stage. Periodic production tests and also used to define the IPR curve after the completion string has been installed in the well. An IPR curve is a plot of the drawdown induced by flowing the well versus the flow rate at the bottom of the well. For a reservoir containing liquids, the drawdown is the difference between the static reservoir pressure and the flowing pressure at the depth of the reservoir. An example of an IPR curve for a liquid reservoir is shown in Figure 10. An IPR curve is specific to the well at the time of testing. Pressure depletion from the reservoir will change the IPR curve. An important application of IPR curves for wells drilled into a particular reservoir system is in the maintenance of production. If one or more wells are shut in, petroleum engineers, using IPR curves, can predict the appropriate choke sizes for flow from other wells in the same field to compensate for lost production. The other important application of IPR curves is in completion design.


15

COMPLETION DESIGN

Figure 8 - Typical Drill Stem Test (DST) String

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COMPLETION DESIGN

Figure 9 - Productivity Index


17

COMPLETION DESIGN

Figure 10 - Example Of An IPR Curve

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COMPLETION DESIGN

1.6

VERTICAL LIFT PERFORMANCE Vertical lift performance (VLP) is concerned with the movement of reservoir fluids from the wellbore at the depth of the reservoir to the production choke on surface. VLP curves are dependent on tubing intake pressures, tubing head pressures, tubing IDs, tubing pressure losses, fluid properties, fluid phase behaviour, and choke performance. The inflow and outflow systems for a well are illustrated in Figure 11.

Figure 11 - Well Outflow And Inflow Systems


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COMPLETION DESIGN

NOTE:

During production, critical flowing conditions are usually maintained at the choke. Maintaining critical flow can be achieved by ensuring the flowing pressure immediately downstream of the choke is restricted to less than 50% of the flowing pressure observed immediately upstream of the choke.

An example of VLP curves for various pipes IDs is shown in Figure 12.

Figure 12 - Typical Vertical Lift Performance (VLP) For Various Tubing Sizes

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COMPLETION DESIGN

Matching the VLP curve to the IPR curve (nodal analysis) will identify which ID will be appropriate for the production required from the well (Refer to Figure 13). Tubing selected on this basis will optimise flow from the reservoir to production facilities. When depletion of a reservoir occurs, VLP curves are utilised to determine the new conduit size to match its new IPR curve.

Figure 13 - Matching VLP Curves With An IPR Curve


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COMPLETION DESIGN

1.7

FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING The design of a completion string involves the selection of components that perform specific functions and these functions are dependent on the philosophy of the operating company. Operating company philosophies differ with respect to completion string design and in some cases there are historic reasons for the inclusion of components that provide specific functions. In this section the functional requirements for a completion string will be discussed here by example. Next, actual completion examples will be illustrated and differing philosophies discussed. Completion Design Example 1 Consider the casing schematic of Figure 14. The objective is to design a completion string for this well with following basic functional requirements: • • • • • •

NOTE:

To provide optimum flowing conditions To protect the casing from well fluids To contain reservoir pressure in an emergency To enable down hole chemical injection To enable the well to be put in a safe condition prior to removing the production conduit (i.e. to be killed) To enable routine downhole operations.

The above functional requirements are not exhaustive.

A completion string that fulfils these functional requirements is illustrated in Figure 14. It is important to realise this example design is only a solution and not the solution. This design is called a single zone single string completion.

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COMPLETION DESIGN

Figure 14 - Completion Design Example 1


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COMPLETION DESIGN

The completion design of Figure 14 also addresses the other functional requirements of: • Suspension the tubing • Compensation for expansion or contraction of the tubing • Internal erosion of the tubing • Protection of the reservoir during well kill operations • Pumping operations for well kill • Well intervention operations out of the lower end of the tubing • Pressure integrity testing • Reservoir monitoring • Installation points for well barriers. The component selection for this completion is shown in Table 2. Functional Requirement

Component

Optimise production

Tubing ID

Casing protection

Tubing hanger Permanent packer

Emergency containment

Safety valve landing nipple (SVLN) Hydraulic control line Wireline retrievable safety valve (WRSV)

Chemical injection

Side pocket mandrel (SPM)

Well kill

Sliding side door (SSD)

Routine downhole operations

Xmas Tree

Tubing string movement

Seal assembly

Extend tubing life

Flow couplings

Support

Tubing hanger

Barrier installation points

Landing nipples Tubing hanger

Pressure testing

Landing nipples

Pumping operations

Piping manifold c/w Choke

Table 2 - Component Selection For Completion Example 1

24

NOTE:

Some components have dual functions.

NOTE:

This completion design utilises a permanent packer and tailpipe that will be installed by wireline techniques or hydraulically via a work string, prior to running the completion string. (Packer systems will be discussed later.)


COMPLETION DESIGN

Completion Design Example 2 Figure 15 shows another example of a single zone single string completion that illustrates additional functional requirements. The component selection for this completion is shown in Table 3. Component

Function

Tubing hanger

Tubing support Tubing to casing seal Barrier installation point

Sub-surface safety valve (SSSV)

Emergency containment

Flow couplings

Tubing protection against internal erosion

Upper side pocket mandrels (SPMs)

Unloading annulus liquids

Lowest side pocket mandrel (SPM)

Point of gas injection

Sliding side door (SSD)

Tubing to annulus circulation Barrier installation Point

Landing nipple

Pressure testing of tubing string Barrier installation point

Retrievable packer

Protect the casing from well fluids Ensure retrievability of all components

Landing nipple

Pressure testing of tubing string Barrier installation Point Installation point for plug to set packer

Perforated joint

Allows flow of fluid when monitoring reservoir performance

Landing nipple (No-Go)

Installation point for pressure/temperature gauges Catches fallen well intervention tools

Re-entry guide

Allows unrestricted re-entry of well intervention tools into the tubing Table 3 - Component Selection For Completion Example 2

NOTE:

This completion utilises a retrievable packer that will be run and set in the casing by the application of pressure to the tubing. (Packer systems will be discussed later.)

The additional functional requirements of this completion design are: • • •

Retrievability of all components from the well Reservoir monitoring Injection of gas in into tubing to assist production.


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COMPLETION DESIGN

Figure 15 - Completion Design Example 2

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COMPLETION DESIGN

1.8

COMPLETION COMPONENTS DESCRIPTIONS The following completion component descriptions follow the completion design of Figure 14 and Figure 15. This completion incorporates components common to many well completions. Workovers are often a result of the failure of a completion component, and thus a good working knowledge of completion components and their purpose is an essential pre-requisite to understanding workover and well control problems.

1.8.1

Re-entry Guide A re-entry guide generally takes one of two forms: • •

Bell guide Mule shoe.

The bell guide (Refer to Figure 16) has a 45° lead in taper to allow easy re-entry into the tubing of well intervention tool strings (i.e., wireline or coiled tubing). This guide is commonly used in completions where the end of the tubing string does not need to bypass the top of a liner hanger. The mule shoe guide (Refer to Figure 16) is essentially the same as the bell guide with the exception of a large 45° shoulder. Should the tubing land on a liner lip while running the completion in the well, the large 45° shoulder should orientate onto the liner lip and guide the tubing into the liner.

Figure 16 - Re-entry Guides


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COMPLETION DESIGN

1.8.2

Landing Nipple A landing nipple (Refer to Figure 17) is a short tubular device with an internally machined profile which can accommodate and secure a locking device called a lock mandrel run usually using wireline well intervention equipment. The landing nipple also provides a pressure seal against the internal bore of the nipple and the outer surface of the locking mandrel. Landing nipples are incorporated at various points in the completion string depending on their functional requirement. Common uses for landing nipples are as follows: • • • •

Installation points for setting plugs for pressure testing, setting hydraulic-set packers or isolating zones Installation point for a sub-surface safety valve (SSSV) Installation point for a downhole regulator or choke Installation point for bottom hole pressure and temperature gauges.

A No-Go landing nipple (Refer to Figure 17) has a small shoulder located within the internal bore of the nipple. The primary reason for a No-Go shoulder is to locate the correct lock mandrel. A secondary function would be to prevent wireline tools from falling out of the end the tubing, if dropped. Only one No-Go landing nipple of the same size can be used in a completion string, the lowermost nipple being the No-Go nipple. More than one No-Go landing nipple can be incorporated in a completion string provided that a step down in NoGo shoulder size is observed.

NOTE:

In highly deviated wells, it may not be possible to use landing nipples at inclinations greater than 70°. Wireline operators commonly use landing nipples for depth references.

Figure 17 - Landing Nipples

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COMPLETION DESIGN

The plugs that may be installed in Landing Nipples are: • • •

Plug with shear disc (pump-open) Plug with equalising valve Plug with non-return valve.

and the choice of plug depends on the pressure control required and the chances of retrieval. 1.8.3

Tubing Protection Joint This is a joint of tubing included for the specific purpose of protecting bottom hole pressure and temperature gauges from excessive vibration while installed in the landing nipple directly above.

1.8.4

Perforated Joint A perforated joint (Refer to Figure 18) may be incorporated in the completion string for the purpose of providing bypass flow if bottom hole pressure and temperature gauges are used for reservoir monitoring. The design criteria for a perforated joint is that the total cross-sectional area of the holes should be at least equivalent to the cross sectional area corresponding to internal diameter of the tubing.

Figure 18 - Perforated Joint


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COMPLETION DESIGN

1.8.5

Sliding Side Door A sliding side door (SSD) or sliding sleeve (Refer to Figure 19) allows communication between the tubing and the annulus. Sliding side doors consist of two concentric sleeves, each with slots or holes. The inner sleeve can be moved with well intervention tools, usually wireline, to align the openings to provide a communication path for the circulation of fluids. Sliding side doors are used for the following purposes: • • • • • •

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To circulate a less dense fluid into the tubing prior to production To circulate appropriate kill fluid into the well prior to workover As a production device in a multi-zone completion As a contingency should tubing/tailpipe plugging occur As a contingency to equalise pressure across a deep set plug after pressure integrity testing As an alternative flow path should a plug become stuck in a wireline nipple.

NOTE:

As with all communication devices, the differential pressure across SSDs should be known prior to opening.

NOTE:

In some areas, the sealing systems between the concentric sleeves are incompatible with the produced fluids and hence alternative methods of producing tubing to annulus communication is used (e.g. side pocket mandrel, tubing perforating).


COMPLETION DESIGN

Figure 19 - Sliding Side Door (SSD)  RIGTRAIN 2002 – Rev 1

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COMPLETION DESIGN

1.8.6

Flow Couplings Flow couplings are used in many completions above and/or below a completion component where turbulence may exist to prevent loss of tubing string integrity and mechanical strength due to internal erosion directly above and/or below the component. Turbulence may be caused by the profiles internal to a component. Flow couplings are thick walled tubulars (of the same internal diameter as the tubing) made of high grade alloy steel usually supplied in 10, 15, or 20 ft lengths and their use depends on internal erosion criteria obtained from fluid velocity and particulate content analysis.

NOTE:

1.8.7

In multi-zone completions, blast joints are commonly used to prevent loss of tubing string integrity due to external erosion resulting from the jetting actions directly opposite producing formations.

Side Pocket Mandrels A side pocket mandrel (SPM) (Refer to Figure 20) along with its through bore, contains an offset pocket which is ported to the annulus. Various valves can be installed/retrieved into/from the side pocket by wireline methods to facilitate annulus-to-tubing communication. Side pocket valves, which provide a seal above and below the communication ports, include: Gas lift valves

When installed in the SPM, the valve responds to the pressure of gas injected into the annulus by opening and allowing gas injection into the tubing. In a gas lift system, the lowest SPM is that used for gas injection into the tubing and the upper SPMs are those used to unload the annulus of completion fluid down to the point of gas injection.

Chemical injection valves

These allow injection of chemicals (e.g. corrosion inhibitors) into the tubing. They are opened by pressure on the annulus side.

Circulation valves

These are used to circulate fluids from the annulus to the tubing without damaging the pocket.

Equalisation valves

Are isolation and pressure equalisation devices that prevent communication between the tubing and the annulus, and can provide an equalisation facility by initially removing a prong from the valve.

Differential kill valves

These are used to provide a means of communication between the annulus and the tubing by the application of annulus pressure. An SPM with a differential valve installed provides the same function as a sliding side door.

Dummy valves

These are solely isolation devices that prevent communication between the tubing and the annulus.

NOTE:

32

An SPM may be used as a circulation device in preference to an SSD as side pocket valves may be retrieved for repair and/or seal replacement.


COMPLETION DESIGN

Figure 20 - Side Pocket Mandrel (SPM)


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COMPLETION DESIGN

1.9

SAFETY VALVES The purpose of a safety valve is to shut off flow from a well in the event of a potentially catastrophic situation occurring. These situations include serious damage to the wellhead, failure of surface equipment, and fire at surface. Many oil operating companies have differing philosophies on the inclusion of safety valve in their completion. For example, in an offshore well, at least one safety valve is placed in every well at a depth which varies from 200 ft to 2,000 ft below the seabed. The depth at which a safety is installed in a completion is dependent on well environment (onshore, offshore), production characteristics (wax or hydrate deposition depth), and the characteristics of the safety valve. (maximum and minimum setting depths)

NOTE:

It is generally recommended that a safety valve is installed in a well that is capable of sustaining natural flow.

In most oil operating areas the installation of a safety valve is governed by law. There are numerous types of safety valves in field operation, but in our case we are going to concentrate on only four types. Two subsurface controlled, and two surface controlled valves. 1.9.1

Types Of Sub-surface Controlled Safety Valve • •

NOTE:

Ambient pressure operated Differential pressure operated.

Both examples are known as ‘Direct Acting’ valves and are classed as pressure activated devices.

Ambient Pressure Activated (Storm Choke) This type of valve is normally closed. The well pressure (hydrostatic or flowing) keeps the valve open. If the well starts to produce at an increase flow rate, the tubing pressure drops and the valve is closed by a spring and pre-charged nitrogen chamber. The valve must be set for the given well conditions and its location in the well. Once closed, the valve can be re-opened by applying tubing pressure above it, or by means of an equalising valve, run on wireline . The valve is popular in many land operations due to its minimal price compared to a surface controlled system. They are often used as back ups for tubing, or wireline retrievable safety valves. They can be of the rotating ball, flapper or ball and seat type. The valve can be installed and retrieved under pressure by wireline methods. Pressure Differential Activated (Velocity Valve or Storm Choke) This type of valve is normally open. The valve operates on a spring loaded flow bean pressure differential principle. The spring holds the valve off-seat until the well flow reaches a predetermined rate. When the pressure differential across the bean exceeds the spring tension the valve is designed to close off the well flow. Once closed, the valve can be re-opened by applying tubing pressure above it, or by means of an equalising valve run on wireline. The valve can be installed and retrieved under pressure by wireline methods.

34


COMPLETION DESIGN

Figure 21 - Otis ‘J’ Differential Pressure Safety Valve


35

COMPLETION DESIGN

Figure 22 - Otis ‘H’ Ambient Pressure Safety Valve

36


COMPLETION DESIGN

1.9.2

Surface Controlled Safety Valves • •

Wireline retrievable valve (WRSV) Tubing retrievable. (TRSV)

Wireline Retrievable Valve This valve is actuated open usually by application of hydraulic pressure from surface via a control line run to the depth of the safety valve. Loss of hydraulic pressure will result in closure of the valve. A number of monitoring pilots or sensing devices can be linked to the surface/subsurface safety system. Each pilot can be set to monitor various flowing and shut-in parameters, and will close the valve to close if a potentially dangerous situation occurs. The valve is run on wireline (slickline) and is installed in a special safety valve landing nipple (SVLN). This SVLN is made up as part of the completion string. A control line which is attached to the completion string by special clamp, provides hydraulic pressure to actuate the valve open. The main advantage of utilising a WRSV is that it can be economically retrieved for inspection. A primary disadvantage of a WRSV is related to its restricted bore, which causes a restriction to flow. The pressure or temperature drop across the valve may cause hydrate or paraffin plugging if an appropriate condition exists. Tubing Retrievable Valve (TRSV) A tubing retrievable safety valve (TRSV) run as part of the tubing string is classified as a TRSV. To open the valve, hydraulic pressure is applied to the valve through a control line attached to the completion string by means of a special clamp. The main advantage of a TRSV is a full bore unrestricted flow through the flapper or ball valve. The full-bore unrestricted flow may reduce or eliminate hydrate or paraffin accumulation. The main disadvantage is that in the event of a critical failure of the valve, the completion string must be pulled and this can be an extremely expensive operation. This disadvantage has been partially overcome by the development of lock open tools and the provision of a surface controlled wireline retrievable insert valve which can be installed in the body of the TRSV. Most valves are installed with a flapper operating mechanism. Examples of the two devices can be found in Figure 23 and Figure 24.


37

COMPLETION DESIGN

Figure 23 - Typical Surface Controlled Wireline Retrievable Safety Valve (WRSV)

38


COMPLETION DESIGN

Figure 24 - Typical Surface Controlled Tubing Retrievable Safety Valve (TRSV)


39

COMPLETION DESIGN

Figure 25 - Annulus Safety Valve

40


COMPLETION DESIGN

1.9.3

Annulus Safety Valves (ASVs) In gas lift systems where large amounts of pressurised gas exists in the tubing-casing annulus, Annulus Safety Valves may be incorporated to contain this gas inventory in the annulus in the event that the wellhead becomes damaged. ASV’s are not discussed here but an example completion design incorporating such a device is shown in Figure 43. An example of an ASV is shown in Figure 25

1.9.4

Tubing Hanger The tubing hanger is a completion component which is landed and locked inside the tubing head spool and provides the following functions: • • •

Suspends the tubing Provides a seal between the tubing and the tubing head spool Installation point for barrier protection

•

Is landed and locked.

The tubing head spool provides the following functions: • • •

Provides a facility to lock the tubing hanger in place Provides a facility for fluid access to the ‘A’ (Production) annulus Provides an appropriate base for the completion Xmas Tree

•

Is landed and locked.

An example of a tubing hanger/tubing head spool system is shown in Figure 26. Such tubing hanger systems allow completion tubing to be suspended in tension (i.e. all the tubing weight minus fluid buoyancy) or the tubing suspended in compression.

NOTE:

Completion strings may be set in compression to accommodate for tubing movement as a result of pumping cold fluids into the tubing, i.e. thermal contraction effects. For example, water injection wells may be set in compression prior to landing the hanger by installing additional tubing in the well. When the water injection system is operating, thermal effects will contract the string appropriate to the additional tubing installed. Setting a completion in compression requires that the tubing-to-packer arrangement be appropriate. (Packer systems will be discussed later.)

NOTE:

Completion strings may also be set in tension to compensate for thermal expansion of the tubing due to production. Setting a completion in tension requires pulling the tubing in tension prior to production and closing rams around a hanger nipple. The hanger nipple is run an appropriate distance below a ram type tubing hanger (Refer to Figure 27) and the tension applied to the tubing string to remove tubing from the well equivalent to that expected from thermal expansion. Setting a completion in tension requires that the tubing-to-packer arrangement be appropriate. (Packer systems will be discussed later.)


41

COMPLETION DESIGN

Figure 26 - Tubing Head Spool/Tubing Hanger System

42


COMPLETION DESIGN

Figure 27 - Ram Type Tubing Hanger System


43

COMPLETION DESIGN

1.9.5

Xmas Tree A Xmas Tree is an assembly of valves, all with specific functions, used to control flow from the well and to provide well intervention access for well maintenance or reservoir monitoring.

NOTE:

The Xmas Tree is normally connected directly to the tubing hanger spool that sits on the uppermost casing head spool. The whole assemblage of Xmas Tree, tubing hanger, and uppermost casing head spool is sometimes referred to as the wellhead.

A Xmas Tree may be a composite collection of valves or, more commonly nowadays, constructed from a single block (Refer to Figure 28). The solid block enables the unit to be smaller and eliminates the danger of leakage from flanges. Typically, from bottom to top, an Xmas Tree will contain the following valves: Lower master gate valve

Manually operated and used as a last resort to shut in a well.

Upper master gate valve

Usually hydraulically operated and also used to shut in a well.

Flow wing valve

Manually operated to permit the passage of hydrocarbons to the production choke.

Kill wing valve

Manually operated to permit entry of kill fluid to into the tubing.

Swab valve

Manually operated and used to allow vertical access into the tubing for well intervention work.

NOTE:

Modern Xmas Tree valves are of the gate-valve type that allows full bore access.

A typical surface wellhead and Xmas Tree are shown in Figure 29.

44


COMPLETION DESIGN

Figure 28 - Typical Xmas Tree


45

COMPLETION DESIGN

Figure 29 - Typical Surface Wellhead And Xmas Tree

46


COMPLETION DESIGN

1.9.6

Production Packers A production packer may be defined as a sub-surface component used to provide a seal between the casing and the tubing in a well to prevent the vertical movement of fluids past the sealing point, allowing fluids from a reservoir to be produced to surface facilities through the production tubing.

NOTE:

By no means are all wells completed with production packers. However, for the purposes of this course, only those packers used in well completions will be discussed.

The prime purpose of using a packer or packers in a well completion is as follows: • • •

To protect the casing from reservoir fluids To protect the casing from the effects of flowing pressures To isolate various producing zones.

In general, packers are constructed of hardened slips, which are forced to bite into the casing wall to prevent upward or downward movement while a system of rubberised elements contact the casing wall to effect a seal. Production packers may be grouped according to their ability to be removed from a well, that is, retrievable or permanent. Retrievable Production Packers Are run on the tubing string and may be set mechanically or hydraulically. They are usually removed from the well by the application of mechanical forces. An example of a retrievable production packer is shown in Figure 30. Permanent Production Packers These may be run in a variety of ways and become an integral part of the casing once set. A permanent packer may be run as follows: •

•

On electric wireline and set in the casing using pyrotechnics to generate the forces required to set it in the casing or On pipe and set hydraulically by the application of pipe pressure.

Figure 31 shows an example of this type of permanent packer.

NOTE:


Both the above methods provide a disconnect mechanism from the setting device. The setting device is removed from the well after the packer has been set. The completion string is then run into the well and a seal assembly stabbed into the polished bore of the packer.

47

COMPLETION DESIGN

Figure 30 - Example Of A Retrievable Packer

48


COMPLETION DESIGN

Figure 31 - Example Of A Permanent Packer


49

COMPLETION DESIGN

Permanent packers may also be run: •

NOTE:

Latched onto the completion tubing and hydraulically set by the application of tubing pressure.

The tubing may be disconnected from the packer by rotation of the latch system or by utilising an expansion joint located in the completion directly above the latch assembly.

Figure 32 shows an example of this type of permanent (hydro-set) packer. Permanent/Retrievable Production Packers These packers have the same mechanical characteristics as permanent packers, but have the facility to be released and recovered from the well. These packers will not be discussed in this course.

NOTE:

50

In general, permanent production packers can withstand greater differential pressures than the equivalent retrievable packer, although recent developments in packer technologies have narrowed the gap between the two types.


COMPLETION DESIGN

Figure 32 - Example Of Hydro-Set Permanent Packer


51

COMPLETION DESIGN

1.9.7

Seal Assemblies Seal assemblies; run on tubing, packs off in the bore of a permanent packer. The sealing element frequently used is the chevron packing ring, fabricated from synthetic rubber, or from plastic such as Teflon. Seal rings are assembled in sets, facing opposite directions, to give a two-way seal. An alternative to chevron seals is the moulded rubber sleeve and in some permanent packer systems a choice of either is provided. Figure 33 illustrates the assemblies available for connecting the tubing to the packer and maintaining a seal. Locator Seal Assembly Locator seal assemblies incorporates a top No-Go shoulder, which locates on the bevel of the packer body, just above the le ft-hand thread. This type of assembly allows the tubing to set in neutral or compression.

NOTE:

Seal assemblies of this type can be used without the locating No-Go shoulder.

Locator seal assemblies do not permit the tubing to be landed in tension. At most the full tubing weight can be hung off at the tubing hanger. However, when the well is producing, the temperature of the tubing will increase and the tubing will expand longitudinally. With the locator seated on the packer, and top of the tubing string fixed in the tubing hanger, expansion can take place only at the expense of buckling. By using a series of seal subs below the locator, the tubing can be pulled back a calculated distance (space-out) and then landed, leaving the locator the same distance above the packer, but with the seal assembly still within the packer bore. This will allow for tubing expansion or contraction. A completion string may also be spaced out appropriately if overall cooling of the tubing string will occur e.g. in a water injection well. Anchor Seal Assembly This seal assembly has a latch sleeve, threaded to match the le ft-hand thread at the top of the packer. The lower part of the sleeve, carrying the thread, has vertical slots cut in it, and the lower flank of the thread is chamfered. On entry into the packer, the latch sleeve collapses inwards, and then springs out to engage the thread of the packer. The anchor seal assembly permits the tubing to be landed in compression, neutral, or tension. The anchor seal assembly can be released from the permanent packer by pulling the tubing in slight tension and rotating the tubing right-handed at surface. The latching sleeve will back out of the packer. Polished Bore Receptacles (PBRs) These are usually anchor latched to a hydro-set packer and run in the well in the closed position (shear ringed, shear pinned, J-slotted). After the packer is set, the PBR may be spaced out appropriately. A PBR affords maximum flow capability through the packer and allows a method of disconnecting from the packer for workover operation.

52


COMPLETION DESIGN

Tubing Seal Receptacles (TSRs) These are usually anchor latched to a hydro-set packer and run in the well in the closed position (shear ringed, shear pinned, J-slotted). After the packer is set, the TSR may be spaced out appropriately. A TSR affords maximum flow capability through the packer and allows a method of disconnecting from the packer for workover operation. A TSR affords protection to the seals. Also, a TSR may be manufactured with circulation ports on the inner mandrel. PBRs and TSRs are shown in Figure 34.

Figure 33 - Seal Assemblies


53

COMPLETION DESIGN

Figure 34 - PBR And TSR Schematics

54


COMPLETION DESIGN

1.9.8

Expansion Joints These are telescoping devices (Refer to Figure 35) usually used in a completion string above a retrievable packer to compensate for tubing movement and possibly to prevent premature release of the packer from the well.

Figure 35 - Expansion Joint


55

COMPLETION DESIGN

1.9.9

Tubing Although tubing is the last string of tubulars to be run in the well, its requirements often dictate the whole well design. Tubing is run mainly to serve as the flow conduit for the produced fluids. It also serves to isolate these fluids from the ‘A’ (Production) annulus when it is used in conjunction with a casing packer. The basic tubing string design criteria are: • • • •

Size, appropriate to producing operations Tensile strength Stress Corrosion resistance.

The American Petroleum Institute (API) identifies, assesses and develops standards for oil and gas industry goods. Tubing is considered appropriate to API standard if the following conform to certain specifications: • • • • • •

Weight per foot Length ranges Outside diameter Wall thickness Steel grade Method of steel manufacture.

and API standards also specify: • •

Physical dimensions of the thread connections Performance for burst, collapse and tensile strength of the pipe body and thread connections.

An API type connection is shown in Figure 36.

56


COMPLETION DESIGN

Figure 36 - API Type Connection API tubing steel grades are identified by letters and numbers which dictate various characteristics of the steel. For each grade, the number designates the minimum yield strength. Thus J-55 grade steel has a minimum yield strength of 55,000 psi. In other words, it can support a stress of 55,000 psi with an elongation of less than 0.5%. The letter in conjunction with the number designates parameters such as the maximum yield strength and the minimum ultimate strength which for J-55 pipe is 80,000 psi and 75,000 psi respectively. Table 4 shows the yield values for various API tubing grades: Grade

Minimum Yield (psi)

Maximum Yield (psi)

Minimum Ultimate Yield (psi)

H-40

40,000

80,000

60,000

J-55

55,000

80,000

75,000

C-75

75,000

90,000

95,000

L-80

80,000

95,000

95,000

N-80

80,000

110,000

100,000

P105

105,000

135,000

120,000

Table 4 - Yield Values For Various API Tubing Grades


57

COMPLETION DESIGN

Grade C-75 is for hydrogen sulphide service and where a higher strength than J-55 is required. In addition to API grades, there are many proprietary steel grades which may conform to API specifications, but which are used extensively for various applications requiring properties such as: • • •

Very high tensile strength Disproportionately high collapse strength Resistance to sulphide stress cracking.

Many tubing strings are run which contain these non-API tubulars. This pipe is made to many but not all API specifications, with variations in steel grade, wall thickness, outside diameter, thread connections, and related upset. Due to these variations, the ratings of burst, collapse, and tensile specifications are non-API. The type of tubing connections selected for a completion will depend mainly on the well characteristics. The connection must be able to contain the produced fluids safely and at the maximum pressures anticipated. The basic requirements of a tubing string connection are: • • • •

Strength compatible with the operational requirements of the string during, and after running Sealing properties suitable for the fluid and pressures expected Ease of stabbing during make-up, and safe breakout when pulling the tubing Resistance to damage, corrosion, and erosion.

There are two types of thread connection, API and Premium. Premium connections are proprietary connections that offer premium features not available on API connections. Most offer a metal-to-metal seal for improved high pressure seal integrity. Premium connections exist with features such as flush connections, recess free bores, and special clearance. An example of a premium thread is shown in Figure 37.

58


COMPLETION DESIGN

Figure 37 - An Example Of A Premium Connection 1.9.10

Sub-sea Wellheads Sub-sea wellheads serve the same function as a surface wellhead in providing support and pressure integrity but are assembled differently. After positioning a guide base on the sea bed which is run with the initial conductor casing, a wellhead is then run on the next string of casing and hung off in the conductor (Refer to Figure 38). This sub-sea wellhead is the basis for further operations. Drilling BOPs are installed in some cases on a special oriented profile on top of the wellhead. The sub-sea Xmas Tree is subsequently latched to the wellhead. (Refer to Figure 39)


59

COMPLETION DESIGN

Figure 38 - Sub-sea Wellhead

Figure 39 - Typical Sub-sea Wellhead And Xmas Tree

60


COMPLETION DESIGN

1.9.11

Examples of Single String Completions 1.

Single Zone Single String Gravel Pack Completion

Refer to Figure 40

2.

Single Zone Single String Water Injection Completion

Refer to Figure 41

3.

Multiple Zone Single String Completion

Refer to Figure 42

4.

Single Zone Single String Completion c/w ASV System

Refer to Figure 43

5.

Dual Zone Single String Completion

Refer to Figure 44

6.

Single Zone Single String Gravel Pack Horizontal Completion

Refer to Figure 45


61

COMPLETION DESIGN

Figure 40 - Single Zone Single String Gravel Pack Completion

62


COMPLETION DESIGN

Figure 41 - Single Zone Single String Water Injection Completion


63

COMPLETION DESIGN

Figure 42 - Multiple Zone Single String Completion

64


COMPLETION DESIGN

Figure 43 - Single Zone Single String Completion c/w ASV System


65

COMPLETION DESIGN

Figure 44 - Dual Zone Single String Completion

66


COMPLETION DESIGN

Figure 45 - Single Zone Single String Gravel Pack Horizontal Completion


67

COMPLETION DESIGN

1.10

DUAL COMPLETIONS Dual completions allow two zones to be produced separately and simultaneously via separate tubing strings. Dual completions maximise the hydrocarbon recovery from a well where the producing zones differ in pressure and/or fluid type. The philosophy behind designing each production conduit is the same as that for a single zone completion possibly with the added contingency for converting the completion to one that allows alternate production from each zone usually up the long string. Apart from using dual hydraulic set production packers (Refer to Figure 46) dual tubing hanger systems (Refer to Figure 47) and dual Xmas Trees (Refer to Figure 48) the completion components used are as that for a single zone completion. To combat erosion of the long string opposite perforations in the upper zone, the long string is fitted with blast joints.

1.10.1

68

Examples of Dual String Completions 1.

Dual zone dual string completion

Refer to Figure 49

2.

Triple zone dual string completion

Refer to Figure 50


COMPLETION DESIGN

Figure 46 - Example Of A Retrievable Dual Production Packer


69

COMPLETION DESIGN

Figure 47 - Segmented Dual Hanger System

70


COMPLETION DESIGN

Figure 48 - Example Of A Dual Xmas Tree


71

COMPLETION DESIGN

Figure 49 - Dual Zone Dual String Completion

72


COMPLETION DESIGN

Figure 50 - Triple Zone Dual String Completion


73

COMPLETION DESIGN

74


BARRIERS AND CONTAINMENTS DEVICES

CONTENTS

1.

BARRIERS AND CONTAINMENT DEVICES

1

1.1

BARRIER TERMINOLOGY

2

1.2

BARRIER ENVELOPE

3

1.3

FLOW CONTROL DEVICES (MECHANICAL BARRIERS) 1.3.1 Blanking Plugs 1.3.2 Check Valve 1.3.3 Pump Open Plug 1.3.4 Pump Out Plugs (Expendable Plugs) 1.3.5 Retrievable Bridge Plugs 1.3.6 Pump Out Subs 1.3.7 Ice Plugs

4 4 4 4 5 5 5 5

1.4

BARRIER INTEGRITY TESTING

8


i


ii



1.

BARRIERS AND CONTAINMENT DEVICES In general, a well barrier is defined as any substance or device that will prevent the flow of a well. A barrier is an obstacle to well flow and pressure. In general, a containment device is a device which becomes a barrier when it is energised. The type and number of barriers and containment devices that must be in place depends on the operation being performed. This is defined by procedures, themselves based on legislation and other requirements combined with experience and accepted practice. Strict definitions exist as to which devices may be regarded as barriers.

NOTE:

1.

Current philosophy requires that two mechanical barriers (for both the annulus and the tubing) and one fluid barrier be considered as the minimum.

Barriers and containment devices in place during normal production: •

•

Downhole SCSSV SCASV Production packer (Element) Annulus fluid. (Over balance) Surface Xmas Tree valves.

NOTE: • • • 2.

There are several barriers which prevent flow up the annulus: Tubing hanger (Seals) Annulus fluid (Over balance) Production packer. (Element)

Barriers and containment devices in place prior to Xmas Tree removal: •

3.

Downhole Workover fluid of sufficient weight to provide an appropriate over balance Wireline plugs. • Surface Back pressure valves. (BPVs) Barriers and containment devices in place after nippling up the BOP: • •

Downhole Workover fluid of sufficient weight to provide an appropriate overbalance Surface Blow out preventers.

NOTE:


There must be procedures in place for each of the three phases of a workover.

1


1.1

BARRIER TERMINOLOGY Barriers can be in the form of mechanical plugs or fluid. Mechanical barriers consist of positive plugs, which are set by well intervention methods, and freeze plugs, which are set by freezing method. A fluid barrier is considered as a barrier when the hydrostatic pressure of the fluid is slightly higher than the formation pressure. All barriers should be tested from the direction of flow by means of a ‘inflow test’. Sometimes it may not be possible to test a barrier from the direction of flow; in this case it should be tested from above. Double barrier protection against well pressure and flow is the recommended minimum requirements for a production well. If a barrier fails, or observations indicate that it is likely to fail, then procedures should be in place to restore or supplement that barrier. Numerous barriers are available for pressure control depending on the status of a well and the operation being performed. A liquid with the appropriate density in the tubing-casing annulus provides the fluid barrier. A fluid barrier may already exist in the annulus or may be circulated in using appropriate devices in the completion string. A fluid barrier that performs pressure control during normal operating condition is a primary barrier. Common fluid barriers are seawater, brine, and drilling mud. Barriers are classified into three categories: Primary barrier

Is a barrier that performs pressure control during normal operating conditions. A primary barrier is usually a closed barrier.

Secondary barrier

Is a barrier that performs pressure control in the event that the primary barrier fails. A secondary barrier is usually a closable barrier.

Tertiary barrier

Is a barrier that performs pressure control in the event of failure of the primary and secondary barrier systems. A tertiary barrier is usually a closable barrier and is the last and final means of pressure control. Usually the tertiary barrier is a shear and seal system.

In general, mechanical barriers are either closed or closable. Closed and closable barrier systems for well intervention equipment are as follows: Production Side Annulus Side Wireline stuffing box Packer/tubing system Grease injection head Tubing hanger Coiled tubing strippers Tubing head spool system Coiled tubing check valves Casing head spool outlet valves Snubbing strippers Tubing hanger spool outlet valves Snubbing string check valves Table 1 - Closed Barrier Systems

2



Production Side Annulus Side Xmas Tree valves BOP rams Annular preventers Shear/seal valves Sub-surface safety valves (?) Annulus safety valves (?) Table 2 - Closable Barrier Systems Production Side Annulus Side Wireline plugs (slickline) Tubing hanger plugs (bpvs) Packer plugs Bridge plugs Cement plugs Ice plugs Ice plugs Table 3 - Additional Barrier Systems

NOTE:

1.2

SCSSCVs and SCASVs my not be classed as appropriate barriers or containment systems as they may not satisfy inflow test criteria as set down by the operating company philosophy and/or government legislation.

BARRIER ENVELOPE Barrier envelope is the whole enclosed flow path that is containing the pressure in a well. In a slick line rig up the envelope barrier is the tree crossover, BOP, lubricator sections, and stuffing box. In the drawing on the following page, the envelope of barrier elements that prevents flow out of the well via the tubing string when the tree is closed is as follows: • • • • • •

Casing below the packer Packer Production tubing Tubing hanger Tubing hanger spool Xmas Tree.

In most parts of the world, the DHSV is not considered as a barrier element because of the leakage rate allowed by API. The DHSV is purely used as a fail- safe emergency shut off valve. Should any one of the elements in this envelope fail, there are various secondary elements which will prevent the escape of well bore fluids from the well. For example, should there be a leak at the packer into the annulus, an overbalanced completion fluid will initially stop the wellbore fluids from reaching the production casing.


3


After a while, this may change as the completion fluid escapes from the annulus and the well bore fluids will then be prevented from leaving the well by the production casing, annulus valves and the tubing hanger seal.

1.3

FLOW CONTROL DEVICES (MECHANICAL BARRIERS) There are very many different devices that can be installed in a nipple. There are a great many different names for the various devices and some of the more common ones are described below.

1.3.1

Blanking Plugs Are attached to the bottom of wireline locks and are run and set in a nipple. They seal off in the nipple and hold pressure from both directions. In this case they may be referred to as positive plugs. Set with one wireline run and pulled with one wireline run, a true blanking plug has no bypass facility on the plug bottom. This makes them very slow to run to the due to the restricted flow around the body and very difficult to pull unless the pressure is exactly equalised across the plug. Normally when speaking about a plug it is a bypass blanking plug. This has a body and a separate inner mandrel. These plugs allow the wellbore fluid to bypass through the plug bottom when running in hole. They may require one or two wireline runs to set them. They are almost always pulled with two wireline runs. The inner mandrel is pulled first allowing equalisation across the plug to take place. It is however, strongly recommended that pressure across the plug be approximately equalised before pulling the mandrel. The mandrel is sometimes wrongly referred to as a prong. The pressure rating of any plug should always be checked if it is planned to pressure up against it from above.

1.3.2

Check Valve Standing valves are usually single wireline tools that are run and set in a nipple. They seal off in the nipple and hold pressure from above only. They are usually used for pressure testing the completion above the valve. They are nearly always fitted with an equalising facility (equalising check valves) which is sheared first as they are pulled. They normally only require one wireline run to set them and, with many designs, it is possible to stay attached to the standing valve (latched on) with wireline whilst the pressure test takes place. They can then be pulled again as soon as the pressure test is complete. They are often used for setting packers. Check valves are also available which hold pressure from below only. Sometimes called ‘Pump through plugs’, they can be used to isolate the well below a certain point while retaining the ability to pump into or kill the well.

1.3.3

Pump Open Plug Pump open plugs are set in a nipple on a wireline lock. They can be run with wireline or preinstalled when a completion component is run. By pressuring up on the top of the plug to a pre-determined level, the inside of the plug shears, which allows flow from below. They are sometimes used in deviated (difficult for wireline) wells in the nipple below the packer. They can be run pre-installed in the nipple so that after the packer has been hydraulically set, the pressure can be increased and the pump down plug opened.

4



The well can now be produced. The plug of course remains in the completion and would have to be removed to run coiled tubing, for example. Some of these plugs are called ‘Pressure cycle plugs’. With this design, the over balance pressure above the plug must be cycled from zero to a pre-set value (perhaps 2,500 psi for example) a fixed number of times before the plug opens. Cycles can be pre-set to anything up to 20. The pressure cycle plug offers more flexibility and security before the plug is opened. 1.3.4

Pump Out Plugs (Expendable Plugs) These are the same in principle as the pump open plug except that when the correct pressure is applied above the plug, the bottom of the plug shears off and is left down hole. They can give a greater flow path than pump open plugs although they have the same disadvantage of leaving a restriction in the nipple.

1.3.5

Retrievable Bridge Plugs Often called explosive set plugs, the most common forms can be set anywhere in the tubing and are usually set by an explosive force, having been run on electric line. In this respect they are like a miniature packer in that they have slips and packing elements. Slickline or coiled tubing can however pull them.

1.3.6

Pump Out Subs Working on exactly the same principle as the pump out plug, they are attached to the bottom of the completion, coiled tubing or snubbing string. When pressured up on and sheared, they leave a smooth full-bore end on the pipe. They can be used when running completions in the same way as a pump open plug. When used with coiled tubing or snubbing, they are a way of getting pipe into a live well and then being able to reverse circulate. Once reversing has finished, a check valve or other device must be run, or pumped in, to allow the pipe to be pulled out.

1.3.7

Ice Plugs This is not a mechanical wireline device. Exceptionally, when all other methods of plugging a well are not possible, an ice plug may be set in a piece of surface equipment. Freeze jobs were originally done by surrounding the item to be frozen with a metal jacket and packing the space between with dry ice (solid CO2). With this method, there is no control over the minimum temperature that the item of surface equipment is subjected to which can damage the structure of the steel. The more modern method involves wrapping the item to be frozen in a special coil through which chemicals like glycol are passed that have been cooled to a pre-determined level in a heat exchanger by liquid nitrogen. In either case, it is necessary to have static (not flowing) fresh water at the point where the plug is to be formed. The process can be slow with plugs taking up to 18 hrs and more to form. Many of these flow control devices are used as mechanical barriers for intervention work and it is important that they are tested to prove that they are holding pressure. It is always considered important to test any barrier from the direction of flow.


5


This applies to any down hole or surface barrier. With down hole plugs, etc. it is usually not possible to apply pressure below the barrier to test that it is holding pressure. In this case, the best solution is to inflow test the device. This is done by bleeding off the pressure above the downhole device and watching for a pressure build up that would show that the device is leaking. It is normal in this situation to bleed down to approximately 100 psi or any suitable amount that can still seen on the surface pressure gauge. It is then much easier to see a small build up on the pressure gauge if the device is leaking. Occasionally it may not be possible to pressure test from below or to inflow test, in which case the only option is to pressure test the device from above. With all mechanical plugs, consideration must be given to the method of pulling the device if there is a danger of debris, etc. settling out on top of the plug. If there is a danger of this happening, mandrel extensions are available which leave room for a certain amount of sand, scale, debris etc. The well pressure containment envelope is shown in Figure 1. This consists of: • • • • •

NOTE:

6

The production casing below packer The packer The production tubing The tubing hanger seal The production Xmas Tree.

The downhole safety valve is not classed as a barrier.



Figure 1 - Barriers Containing Well Pressure


7


1.4

BARRIER INTEGRITY TESTING After the installation of a barrier in a well, that barrier should be pressure integrity tested. Pressure integrity testing on closed barriers should display a zero leak off rate. Pressure integrity testing on closable barriers should display a leak off rate below that specified by operating company philosophy. All devices which are to be used as barriers or containment devices, will be pressure tested before use. The lowermost mechanical barrier in a live well will always be integrity tested against the well pressure with which it must contain. Pressure integrity testing under these circumstances will be to bleed off the pressure in the tubing and then monitor for pressure build up over a specified period of time (e.g. 30 minutes). This barrier may also be tested from above (if possible) to some pressure above formation pressure if specified in the workover procedure. The next mechanical barrier should be tested from above to avoid trapping pressure underneath with no means of bleeding off.

NOTE:

Testing barriers from above can be limited by the shear pin rating of pump-open plugs (if used) and can also be limited by the pressure rating of the wireline lock mandrel to pressure from above.

The procedure for testing the upper barrier from above will be to pressure up the Xmas Tree and tubing above the barrier to the test pressure using the cement pump or surface pump unit, shutting in on surface and then monitoring for pressure fall off. When testing a plug or dummy SCSSV in an SVLN, the plug should first be tested by pressuring up on the SCSSV control line to the operating pressure of the SCSSV; this will test both seal stacks on the dummy valve. Testing from above will only test the top seal stack. The term ‘Back pressure valve’ is often used to describe any kind of pressure control device that is set in the tubing hanger profile. In fact, this term should only be applied to the check valve type devices which hold pressure from below only and which cannot be tested from above. A test dart may be installed in the back pressure valve to allow testing from above during Xmas Tree installation or repairs. Even if this is the case, the test from above will not test the mechanical sealing device inside the valve, but only the seal between the device and the tubing hanger profile. In general, backpressure valves, if being used, will not be inflow tested.

8



CONTENTS

1.


1

1.1

INTRODUCTION

1

1.2

REASONS FOR WORKOVER 1.2.1 Equipment Failure 1.2.2 Well Performance Problems 1.2.3 General

1 1 2 2

1.3

WELL WORKOVER 1.3.1 Workover Planning 1.3.2 Workover Programs 1.3.3 Well Control Problems During Workover

3 3 4 5

1.4

WORKOVER EXAMPLE

6


i


ii



1.


1.1

INTRODUCTION Once a well has been drilled and completed it will be utilised to produce from or inject fluid into the formation. Workover is the term that is commonly used to describe the process anytime the well is entered after it is completed. This normally involves a process to stop the well producing hydrocarbons, so that the purpose for which it has been entered may be carried out in a safe and controlled manner.

1.2

REASONS FOR WORKOVER Problems associated with well completions account for the majority of workovers conducted on oil and gas wells. The necessity to perform a workover may be due to a problem in one of two categories:

1.2.1

1.

Equipment failure

2.

The need to replace/change the completion string due to well performance problems or other reservoir management needs.

Equipment Failure A typical completion string has many components and sometimes is designed with an incomplete knowledge of the likely conditions for the full life of the well. Equipment may fail for a number of reasons including: • • • • •

Effects of pressure Effects of thermal stress Applied and induced mechanical loading Corrosion failure (O2, CO2, H2S, Acids) Erosion.

It is also important to distinguish two types of failure, namely: 1.

Catastrophic failure implying a safety concern e.g. tubing leak.

2.

Inability to function with no immediate significant safety concerns e.g. gas lift valve failure.

Failure of equipment may dictate two courses of action: 1.

Repair or removal and replacement.

2.

Abandon the well in cases where due to safety implications the well is not salvageable.


1


Typical component failures include: • • • • • •

Tubing failure Packer failure Failure of a flow control device (e.g. SCSSV, SSD) Xmas Tree, tubing hanger failure or leakage Failure of gas lift valve and/or SPM Downhole pump failure.

The consequences of a component failure depends upon its integration with the completion string and its replacement may require: • • • • 1.2.2

Removal and replacement by means of wireline or coiled tubing without having to kill the well. Removal and replacement of the Xmas Tree. Partial or full removal and replacement of the completion string. Other remedial work.

Well Performance Problems Workovers designed to improve the vertical lift performance of wells are very common. Workovers conducted in this way can be directed at: • •

The improvement or restoration of the performance of the well under natural lift. The installation or replacement of artificial lift equipment.

The two major factors affecting well performance are reservoir pressure and water cut, and changes in completion design have to be made accordingly. 1.2.3

General It may not always be possible, or desirable, to perform a workover immediately, if for example, the means are not readily available. In this case the well may be: • • •

2

Shut-in, if there is no safety problem, e.g. this may be the case of high water cut. Temporarily suspended, if there is a safety problem, such as a tubing leak. This involves installing the required number of mechanical and fluid barriers so that the well is rendered safe. Abandoned, if the problem is so severe that it is not safe or economical to perform a workover. This may occur if there are major well performance problems or irretrievable junk in the well. In this case, permanent barriers such as cement plugs will be placed in the well, perhaps along with other requirements such as removing the Xmas Tree.



1.3

WELL WORKOVER The following methods can be used to workover a well: • • • •

Drilling/Workover rig Wireline Intervention System Coiled Tubing Intervention System Hydraulic Workover System (Snubbing).

It will be clear that the hazards associated with workover operations must be identified and procedures put in place to minimise or eradicate the hazard. This is clearly tied in to planning and programming the workover for the rig or whatever the type of workover unit is used. The following information is provided with the rig workover in mind. 1.3.1

Workover Planning Clearly, well control is the key safety element in any workover plan and must be reflected in the workover program. Workover planning and the subsequent production of workover programs is ‘second nature’ to those engineers who are continually involve in that process - this is not necessarily true of all of those involved in the chain of communication from planning to the execution of the workover. Individuals preparing/updating the safety and management system (SMS) will have involved the well operations group so that the documentation used in the planning and execution of workovers is an integral part of the SMS. It would be useful for well operations groups to highlight the mechanism for supervisors in charge of well operations at the site to communicate proposed changes in the workover program to the onshore co-ordinator, and the method of responding to the proposed changes. This may seem unnecessary to those continually involved in that process, but if there is a change out of personnel, illness or vacation the ‘norm’ could become the abnormal and problems could ensue that may affect safety and costs. Most well operations groups include well diagrams showing barriers and containment devices in the well before, during and after the workover and well files are updated accordingly. There is normally feedback to adjust procedures, where necessary, after a post workover review and this may include changes in barrier philosophy.


3


1.3.2

Workover Programs Having established the objective for a workover, a program is produced. The following is an example of the main headings of the contents of a typical program for a producing well. 1.

Well history

2.

Current status of the well

3.

Proposed completion details

4.

Proposed deviation from standard procedures (if any)

5.

Procedures for. • • • • • • • •

Well kill Plugging Removal of Xmas Tree Installation of BOP Cleaning out the well Running the completion Removing the BOP Re-installing the Xmas Tree.

From a well control perspective we would want to have specific information on: • • • • • • •

Pore pressure of exposed formations Fracture pressure of exposed formations Permeability of exposed formations Accessibility to tailpipe nipples Integrity of packer and tubing hanger Current wellhead annuli info on pressures Hydrate formation

Kill fluid requirements Bullheading requirements Kill fluid specifications Barrier considerations Procedures to control the well Procedures to control the well Procedures to control the well

From an operational point of point of view the following should be considered: • • •

Disposal of contaminants Personnel protection Prevalence/likelihood of hydrogen sulphide (H2S) and low specific activity (LSA) scale radioactivity.

As discussed earlier, careful considerations should be given to the BOP configuration, particularly with respect to the workover objective and anticipated problems.

4



The following considerations also apply: All pressure control equipment, ie. BOPs, risers, lubricators should: • •

Be rated to at least the maximum anticipated surface pressure Be suited to the working environment allowing for: Temperature e.g. BOP elastomeric components Corrosive effects e.g. CO2, H2S, and brines • Allow passage of all toolstring components. Allowance should be made for the possibility of operations such as bullheading.

NOTE:

1.3.3

Typically the pressure rating of BOPs will be the same as that for the Xmas Tree, unless there has been considerable reservoir pressure depletion during the life of the well.

Well Control Problems During Workover The following are typical causes of well control problems during workover: 1.

Different workover philosophies within the same company for different fields can lead to subtle changes in procedures which in turn can lead to errors.

2.

In some cases there is no test of mechanical barriers from below the barrier.

3.

Attempting to remove a toolstring from a well having insufficient length of riser to isolate the formation and isolate to depressurise the toolstring

4.

Brine densities can be considerably affected by downhole pressures and temperatures. This is particularly hazardous where a low overbalance margin exists.

In many cases the procedures initially proposed will fail because they may have to be modified in the light of new facts uncovered during the process of the workover operation. Many aspects must be considered before developing procedures.


5


1.4

WORKOVER EXAMPLE The objective of this workover is to remove a permanent packer from a production well with a surface Xmas Tree (Refer to Figure 1 - Figure 4). In this case the well must be killed, the tubing pulled from the well, the packer milled, and a new packer installed. The following is a general list to consider: 1.

Permit to work Well handover certificate sharing status of the well. heavy lift. Isolation and de-pressurisation of wellhead prior to plugging well. Close liaison with production and clear lines of communication.

2.

COSHH Safe handling of corrosive brines. Protection against biocides and other additives.

3.

Well control Kill procedures either by bullheading and reverse circulation; communicate via sliding side door or punch holes in the tubing. Displace tubing contents to test separator for disposal. At this stage, the well may be secured by installing plugs which fit specific landing nipples or bridge plugs which can straddle the hole and secure it at any depth in the tubing. To install plugs, a wireline well intervention method will be necessary.

4.

Pressure test wireline intervention equipment Cordon off wireline work area between wireline unit and the wellhead. Tool string picked up by air tuggers. Ensure appropriate signalling system being used to aid those positioning tool string on Xmas Tree. No barriers are in place in the tool string but we do have several containment devices if for any reason the well starts to flow:

6

Stuffing box

Containment device

Safety check union

Containment device

Lubricator

Functional device

Tool trap

Functional device

Wireline BOP

Containment device



Leaks/containment problems may be as follows: •

•

•

•

Major Leaks Due to main sealing device failure Due to freezing rendering sealing devices inoperative Due to absence of cable Due to elastomer failure Due to riser/lubricator failure. Minor Leaks In gas well In sour wells Through closed BOPs. Operating problems leading to leaks Fragile cable breaking/stranding Air/grease supply failure. Well kill situation Tubing blocked Secondary well control device failure. (e.g. BOPs)

NOTE:

Three plugs have been installed i.e. In tailpipe, in SCSSV profile, and in tubing hanger profile (BPV).

Procedures are also required for: • • • •

Depressurising lubricator Rigging down equipment Heavy lift - remove Xmas Tree Heavy lift - replace rig BOPs.

The details of how further operations are carried out will not be discussed here, but the available barriers have been indicated. As stated previously, procedures for all steps outlined in workover will be necessary until the well is handed back to production. A workover to remove a permanent packer from a production well with a Sub-sea Xmas Tree is shown in Figure 4 and Figure 8


7


Figure 1 - Well Closed In Prior To Well Kill

8



Figure 2 - Well Killed And Barrier In Place For Tree Removal


9


Figure 3 - BOP Removed And Tree Replaced After Workover

10



Figure 4 - Sub-sea Well - BOP Installed - Tubing Hanger Running Tool In Place - Prepare To Rig Up Wireline


11


Figure 5 - Sub-sea Well - Prepare To Pull Tubing

12



Figure 6 - Sub-sea Well - Tubing Removed - Wear Bushing Installed


13


Figure 7 - Sub-sea Well - Milling The Packer

14



Figure 8 - Sub-sea Well - Running New Tubing


15


Figure 9 - Sub-sea Well - Plugs Removed - Prepare To Pull Tubing On Tubing Hanger Running And Orientation Tool

16



Figure 10 - Sub-sea Well - Tubing Removed


17


Figure 11 - Sub-sea Well - Milling The Packer

18



Figure 12 - Sub-sea Well - New Tubing Run On Tubing Hanger Running And Orientation Tool


19


Figure 13 - Sub-sea Well - Plugs Run Prior To Nipple Down BOP

20



Figure 14 - Sub-sea Well - BOP And Drilling Riser Pulled Tree Run On Workover Package


21


22


BASIC PRINCIPLES OF HYDROSTATICS

CONTENTS

1.


2

1.1

LIQUID HYDROSTATIC PRESSURE INTRODUCTION 1.1.1 Specific Gravity 1.1.2 API Gravity 1.1.3 Example Application of Hydrostatic Equations to Liquid Wells

2 7 8 9

1.2

GAS HYDROSTATIC PRESSURE INTRODUCTION 1.2.1 Hydrostatic Pressure Due To A Gas Column

12 12

1.3

GAS/LIQUID HYDROSTATIC PRESSURE INTRODUCTION 1.3.1 Example Hydrostatic Pressure Due To Combined Gas and Liquid Columns

15 15

1.4

WELL VOLUMETRIC CALCULATIONS

19


1


1.


1.1

LIQUID HYDROSTATIC PRESSURE INTRODUCTION The basic principles of pressure control may be found in the science of hydrostatics, which deals with the forces generated by fluid columns under static conditions. These forces are produced by the effects of gravity. If well engineers can determine the magnitude of these forces, then they can predict the effects of such forces on the various components installed in a well at various depths. The weight of a fluid is referred to as its density. A column of fluid exerts a pressure on the walls and on the bottom of a well bore. If this fluid is stationary and not being circulated around, it will exert a pressure that is commonly referred to a hydrostatic pressure. The hydrostatic pressure of a fluid is a direct function of depth and density. The units of density will be expressed as: US pounds per gallon (ppg) or Pounds per Cubic feet (lbf/ft3) or Specific gravity (SG) or API gravity (American Petroleum Institute) degrees API The unit of pressure will be in Pounds Per Square Inch (psi). The unit of depth will be in Feet (ft)

NOTE:

2

When calculating hydrostatic pressure the true vertical depth (TVD) is used. Measured depth (MD) is used only to calculate capacities and volumes. Figure 1 shows that measured depths will be greater than true vertical depths if the hole is deviated.



Figure 1 - TVD v MD


3


Figure 2 - 1ft Cubed Container 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/ft2

1 ft2 = 12 ins × 12 ins area = 144 ins2, therefore the pressure per ins2 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.

4



Examples:

Fresh water has a density of 8.33 ppg To convert the density of fresh water 8.33 ppg into a pressure gradient:

8.33 ppg × 0.052 = 0.433 psi/ft. So the gradient of fresh water is 0.433 psi/ft. To convert a fluid density of 10 ppg into a pressure gradient:

10 ppg × 0.052 = 0.52 psi/ft. So the gradient of a fluid density of 10 ppg is 0.52 psi/ft.

NOTE:

The reference fluid for all liquid pressure calculations is fresh water.

It there for follows that to convert a gradient of fresh water back to a density in ppg the calculation below should be used. To convert the gradient of fresh water into a density:

0.433 psi / ft 0.052

NOTE:

=

8.33 ppg

The constant 0.052 is probably the most useful constant used in pressure calculations.

In the container shown in Figure 2 the weight of the water may be expressed as a pound force (lbf). The water in this container weighs 62.4 lbf. This force, however, is distributed over a square area of 144 square inches. The force per square inch is given by the formula below: Where F A

= =

lbf Area

F 62.4 lbf = = 0.433 lbf / ins 2 or psi 2 A 144 ins Now consider another container with the same volume but with a base of 6 inches by 24 inches and a height of 12, again filled with fresh water. The force per square inch is given by: F 62.4 lbf = = 0.433 lbf / ins 2 or psi A 144 ins 2 In fact, provided we keep the height of each container the same then the force per square inch on the base remains 0.433 psi regardless of the dimensions of the sides of the base.


5


Now consider another container of the same volume but with a base of 12 inches by 48 inches and a height of 3 inches, again filled with fresh water. The weight of water in such a container is still 62.4 lbf. The force per square inch is given by: F 62.4 lbf = = 0.108 lbf / ins 2 or psi 2 A 576 ins Clearly, the force per square inch is less because the containers height is less than that of the previous containers. Since the (imperial) unit of depth in the oilfield is the foot, we will re-consider the container of 1 foot cubed to generate important quantities relating to fluids at rest. For fresh water of density 62.4 lbf/ft3: • • •

The hydrostatic pressure exerted at on the base of a container 1 foot in height is 0.433 psi The hydrostatic pressure exerted at on the base of a container 2 feet in height is 0.866 psi The hydrostatic pressure exerted at on the base a container 3 feet in height is 1.299 psi.

Thus, for every 1ft increase in TVD the pressure increases by 0.433 psi. This increase in pressure per unit increase in depth is called the pressure gradient, and as shown for fresh water is 0.433 psi/ft. The hydrostatic pressure for a well will be its gradient multiplied by the TVD, i.e. Thus for a 10,000 ft well filled with fresh water the hydrostatic pressure would be: Hydrostatic pressure = Gradient × Depth = 0.433 ×10,000 = 4,330 psi

For a liquid of density 77 lbf/ft3: •

The hydrostatic pressure exerted at on the base of a container 1 foot in height is 0.535 psi (77/144) • The hydrostatic pressure exerted on the base of a container 2 feet in height is 1.069 psi • The hydrostatic pressure exerted on the base a container 3 feet in height is 1.604 psi. Thus, for every 1 ft increase in depth the pressure increases by 0.534 psi. This increase in pressure per unit increase in depth is called the pressure gradient, and is 0.534 psi/ft for this liquid of density 77 lbf/ft3. The hydrostatic pressure for a well will be its gradient multiplied by the TVD, i.e. Thus for a 10,000 ft well filled with a liquid of density 77 lbf/ft3 the hydrostatic pressure would be: P = Fluid gradient × TVD = 0.534 × 10,000 = 5,340 psi

6



1.1.1

Specific Gravity

Fresh water may be used as a universal standard since it may be obtained relatively easily in any part of the world. In the oilfield it is common practice to used the density of fresh water as the standard and compare all other liquids densities to this standard, (as shown for ppg and lbf3) The specific gravity of a liquid is defined as the ratio of the density of the liquid to the density of fresh water and is therefore a unit-less quantity. The SG of fresh water is 1. SG of Liquid =

Density of Liquid Density of Fresh Water

Example

The SG of a liquid with a density of 77 lbf/ft3 is SG of Liquid =

Density of Liquid 77 lbf / ft 3 = = 1.234 Density of Fresh Water 62.4 lbf / ft 3

The quantity SG = 1.234 means that the liquid in question is 1.234 times more dense (and thus heavier) than fresh water. Similarly a liquid with an SG = 0.76 is less dense (and less heavy) than fresh water. If the SG of a liquid is quoted rather than its density then the increase in hydrostatic pressure per unit increase in depth (i.e. its gradient) must be its SG multiplied by the gradient of fresh water. That is: Gradient of Liquid = Liquid Specific Gravity × Gradient of Fresh Water = Liquid Specific Gravity × 0.433 Example

The density of an oil field brine is 68.4 lbf/ft3. Calculate the specific gravity, pressure gradient, and the hydrostatic pressure due to an 11,375 ft true vertical column of this brine. 1.

Specific gravity Fluid lbf / ft 3 68.4 = = 1.096 SG 3 Fresh Water lbf / ft 62.4

2.

Pressure gradient SG × Gradient of Fresh Water = 1.096 × 0.433 = 0.475 psi / ft

3.

Hydrostatic pressure Pressure Gradient × TVD = 0.475 × 11,375 = 5,403 psi


7


1.1.2

API Gravity

The American Petroleum Institute (API) system for expressing fluid density was introduced to standardise the weight of oilfield fluids at a base temperature of 60°F. Fresh water is again used as the standard reference fluid, and has an API gravity of 10°. For wells that produce oil or condensate the API gravity of such liquids may be given rather than the density (ppg or lbs/ft3), pressure gradient (psi/ft), or the specific gravity (SG). The API gravity of an oil or condensate can be related to its specific gravity by the empirical equation: SG =

141.5 131.5 + °API

or, to find an API, API =

141.5 − 131.5 SG

The API gravity of an oil or condensate is measured using a hydrometer in conjunction with a thermometer to convert the observed API at the observed temperature to the corrected API at 60° f.

NOTE:

API gravity is a term commonly used by production personnel. H2O

0

10

Black/Green Oils 20

30

Diesel 40

High viscosity

Condensate 50

60

70

Low viscosity Table 1 - API Gravity Scale

8



1.1.3

Example Application of Hydrostatic Equations to Liquid Wells

Consider the well shown in Figure 3. The following data is pertinent: • • • • • •

Full column of fluid to surface Surface pressure 0 psi Oil from surface to 5,500 ft, API Gravity 38° Fresh water from 5,500 ft to 6,750 ft, 8.33 ppg Formation water from 6,750 ft to 9,200 ft, 9.6 ppg Top of perforations at 9,200 ft.

Calculate the reservoir pressure. The process is as follows:

Step 1

Draw a diagram

Step 2

Calculate hydrostatic pressure due to oil column

Step 3

Calculate hydrostatic pressure due to fresh water column

Step 4

Calculate hydrostatic pressure due to formation water column

Step 5

Calculate total hydrostatic pressure at the perforations.

The calculations are as follows:

Step 1

Refer to Figure 3.

Step 2

Calculate hydrostatic pressure due to oil column SG =

141.5 141.5 = = 0.835 131.5 + °API 131.5 + 38.0

Hydrostatic pressure = SG × 0.433 × TVD = 0.835 × 0.433 × 5,500 = 1,989 psi

Step 3

Calculate hydrostatic pressure due to fresh water column Hydrostatic pressure = Fresh water (ppg) × 0.052 × TVD = 8.33 × 0.052 × 1,250 = 541 psi


9


Figure 3 - Well Schematic For Calculation

10



Step 4

Calculate hydrostatic pressure due to formation water column P = Formation water ( ppg ) × 0.052 × TVD = 9.60 × 0.052 × 2,450 = 1, 223 psi

Step 5

Calculate the total hydrostatic pressure at the top of the perforations by adding the hydrostatic pressures of the three columns together

1,989 + 541 + 1, 223 = 3,753 psi Addition Of Surface Pressure To Above Example

The previous calculation was performed for a shut in tubing head pressure (SITHP) also known as closed in tubing head pressure (CITHP) of 0 psi. If a SITHP were present, it would be directly added to the total hydrostatic pressure of the individual columns in the well. Thus if the SITHP was 2,000 psi, then the hydrostatic pressure at the top of the perforations would be: = 1,989 + 541 + 1, 223 + 2,000 = 5,753 psi


11


1.2

GAS HYDROSTATIC PRESSURE INTRODUCTION

1.2.1

Hydrostatic Pressure Due To A Gas Column

There are 3 ways to calculate the pressure exerted at the base of a gas column. Method 1

By using the gas correction factor table

Method 2

By calculation using a formula

Method 3

If the gas gradient is known, by multiplying by the TVD

The specific gravity (SG) of a gas (also referred to as the gas gravity, or relative density) is measured when the gas is under standard reference conditions that are taken to be 60°F at one atmosphere pressure. The device used for this measurement in the field is the gas gravitometer, more commonly known as a Ranarex. Up till now we have been using fresh water as our reference point. For gas calculations, the reference substance is air, which is given as 1.0. Hydrocarbon gasses are normally lighter than air, typically 0.6 to 0.9 relative to air. The formula shown in example 2 is useful when the gas being investigated is outside of the table range. Method 1

If the SITHP, gas SG and TVD are known, the gas correction factor table can be used. Example:

A gas well has a TVD of 5,000 ft, a shut-in surface pressure of 2,000 psi and has a SG of 0.6. Calculate the pressure at the base of the column (BHP): 1.

Find the depth in the left hand column of the correction factor table (Refer to Table 2)

2.

Find the gas gravity column corresponding to 0.6 SG along the top of the table

3.

Where the two converge this is the correction factor required.

Gas correction factor from the table = 1.1098 × SITHP (2,000psi) = 2,220 psi

12



Depth (ft)

0.60

1,000 1,500 2,000 2,500 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 15,5,00 16,000 16,500 17,000 17,500 18,000

1.0210 1.0371 1.0425 1.0535 1.0645 1.0756 1.0869 1.0983 1.1098 1.1214 1.1331 1.1450 1.1570 1.1691 1.1813 1.1937 1.2062 1.2188 1.2316 1.2445 1.2575 1.2707 1.2840 1.2974 1.3110 1.3247 1.3386 1.3526 1.3668 1.3811 1.3956 1.4102 1.4249 1.4398 1.4549

0.65

Gas Specific Gravity (SG) 0.70 0.75 0.80

0.85

0.90

1.0228 1.0344 1.0462 1.0580 1.0700 1.0822 1.0945 1.1069 1.1194 1.1312 1.450 1.1580 1.1711 1.1844 1.979 1.2114 1.2252 1.2391 1.2532 1.2674 1.2818 1.2963 1.3110 1.3259 1.3409 1.3561 1.3715 1.3871 1.4028 1.4188 1.4349 1.4511 1.4676 1.4843 1.5011

1.0246 1.0371 1.0498 1.0626 1.0750 1.0888 1.1021 1.1156 1.1292 1.1430 1.1570 1.1711 1.1854 1.1999 1.2146 1.2295 1.2445 1.2597 1.2751 1.2907 1.3065 0.3224 0.3386 1.3550 1.3715 1.3883 1.4053 1.4225 1.4398 1.4575 1.4753 1.4933 1.5116 1.5300 1.5487

1.0299 1.0453 1.0608 1.0766 1.0926 1.1088 1.1253 1.1420 1.1590 1.1762 1.1937 1.2114 1.2295 1.2477 1.2663 1.2851 1.3042 1.3236 1.3433 1.3632 1.3835 1.4041 1.4249 1.4461 1.4676 1.4894 1.5116 1.5340 1.5568 1.5800 1.6035 1.6273 1.6515 1.6760 1.7009

1.0317 1.0480 1.0645 1.0812 1.0993 1.1156 1.1331 1.1510 1.1691 1.1875 1.2062 1.2252 1.2554 1.2641 1.2840 1.3042 1.3247 1.3456 1.3668 1.3883 1.4102 1.4324 1.4549 1.4778 1.5011 1.5247 1.5487 1.5731 1.5979 1.6231 1.6486 1.6746 1.7009 1.7277 1.7549

1.0264 1.0398 1.0535 1.0673 1.0812 1.0954 1.1098 1.1243 1.1390 1.1540 1.691 1.1844 1.1999 1.2157 1.2316 1.2477 1.2641 1.2806 1.2974 1.3144 1.3317 1.3491 1.3688 1.3847 1.4028 1.4212 1.4398 1.4587 1.4778 1.4972 1.5168 1.5367 1.5568 1.5772 1.5979

1.0282 1.0425 1.0571 1.0719 1.0869 1.1021 1.1175 1.1331 1.1490 1.650 1.813 1.979 1.2146 1.2316 1.2488 1.2663 1.2840 1.3019 1.3201 1.3386 1.3573 1.3763 1.3956 1.4151 1.4349 1.4549 1.4753 1.4959 1.5168 1.5380 1.5595 1.5813 1.6035 1.6259 1.6486

Table 2 - Gas Correction Factors


13


Method 2

If the correction factor table is not available the following equations can be used. The first equation is an accurate alternative to the correction factor table. The second is a drilling estimation which has a built in over balance of approximately 30 psi in this case: 1. Ratio

Surface Pr essure 1 = 0.000034 × SG × D BHP 2.718 = 0.000034 × 0.6 × 5,000 = 0.102 = 2.718 0.102 = 1.107 1 Which Gives = = 0.903 1.107 2000 = = 2, 214 psi 0.903

2.  2,000  5,000  BHP = Surface Pr essure + (2.5 )    100  1,000  = 2,000 + (2.5 ) × 20 × 5 = 2, 250

NOTE:

These equations are useful where the gas in question has an SG out-with the scale of the correction factor table

Method 3

If the SITHP, gas gradient and TVD are known, we can simply multiply the gas gradient by the TVD and add the SITHP to find the pressure at the base of the column Using the well example above, the difference between the pressure at the base of the column, and the SITHP is: 2,220 psi – 2,000 psi = 220 psi. The pressure difference between the two values, must be the pressure exerted by the gas itself. We can therefore calculate the gas gradient in psi/ft. Gas gradient = 220 psi divided by the length of the column (5,000 ft) = 0.044 psi/ft. Once the gradient is known, we simply multiply by the depth, and add the SITHP to find the total pressure exerted at the base of the column. For the above example: 0.044 (gas gradient) × 5,000 ft + 2,000 psi = 2,220 psi

14



1.3

GAS/LIQUID HYDROSTATIC PRESSURE INTRODUCTION

1.3.1

Example Hydrostatic Pressure Due To Combined Gas and Liquid Columns

A well is to be killed and has been shut in. Bottom hole pressure gauges were run to identify fluid interfaces, fluid gradients and bottom hole pressure. The following data is pertinent: • • • • • • • •

CITHP 2,480 psi Gas from surface to 3,560 ft, SG = 0.75 Oil from 3,560 to 7,840 ft, 32.6°API Formation water from 7,840 ft to top of perforations at 10,280 ft, 9.6 ppg CIAHP 0 psi Annulus full of 9.85 ppg brine Side pocket mandrel c/w dummy valve at 10,230 ft Packer at 10,300 ft

•

Formation fracture pressure 7,000 psi

The status of this well is illustrated in Figure 4. Calculate: 1.

The reservoir (or formation) pressure

2.

The differential pressure between tubing and annulus at the depth of the SPM.

3.

The formation gradient Reservoir pressure / TVD

4.

The kill fluid gradient with an over balance of 200 psi Reservoir pressure + 200 psi / TVD

5.

The formation fracture gradient Reservoir fracture pressure /TVD

6.

Suggest how you would equalise pressures prior to pulling the dummy valve.


15


Figure 4 - Well Schematic for Calculation

16



Solution for 1

1.

Calculate the pressure exerted at the bottom of the gas column: = 2,480 × 1.0954 = 2,717 psi

2.

Calculate hydrostatic pressure due to the oil column: 141.5 141.5 = = 0.862 131.5 + °API 131.5 + 32.6 Oil gradient = 0.862 × 0.433 = 0.373 psi/ft P = Gradient × TVD = 0.373 × 4280 = 1,597 psi Calculate the hydrostatic pressure due to the formation water column to the top of the perforations: SG =

3.

P = 9.6 × 0.052 × TVD = 9.6 × 0.052 × 2,440 = 1, 218 psi

4.

Total pressure exerted at the top of the perforations (reservoir pressure): BHP = 2,717 gas + 1,597 oil + 1, 218 water = 5,532 psi

Solution for 2

Calculate hydrostatic pressure in tubing at SPM: The hydrostatic pressures for the gas and oil columns have already been calculated. 1.

The formation water hydrostatic pressure inside the tubing, down to the ports on the SPM is: = 9.6 × 0.052 × 2,390 = 1,193 psi

= 2,717 + 1,597 + 1,193 = 5,508 psi 2.

Calculate the hydrostatic pressure to SPM ports in the annulus: 9.85 × 0.052 × 10230 = 5, 240psi

3.

Calculate differential pressure from tubing to annulus. 5,508 − 5, 240 = 268 psi

Solution for 3

Calculate the formation gradient 5,532 psi /10,280 ft TVD = 0.54 psi/ft (or 10.38 ppg) Solution for 4

Calculate the kill fluid gradient 5,532 psi + 200 psi = 5,732 psi / 10,280 ft TVD = 0.56 psi/ft (or 10.77 ppg)


17


Solution for 5

Calculate the formation fracture gradient 7,000 psi / 10,280 ft TVD = 0.68 psi/ft (or 13.08 ppg) Solution for 6

Equalisation of pressures may be achieved by applying approx. 268 psi to the annulus.

18



1.4

WELL VOLUMETRIC CALCULATIONS To calculate well volumes, the inside and outside diameters of the tubular goods in the well must be known. Consider the well of Figure 5 the following data is pertinent: • • • • • • •

Casing ID Tubing OD Tubing ID Tubing Weight Depth of SSD Depth of packer Depth of perforations

6.154 ins 2.875 ins 2.441 ins 6.4 lbf/ft 8,210 ft 8,260 ft 8,310 ft

Calculate: 1.

The volume of the annulus.

2.

The tubing volume above the SSD.

3.

Total well volume to the circulating device with the tubing in the well.

4.

The time to circulate kill fluid in the well at 0.75 bbl/minute.

NOTE:


To calculate circulating volumes and times the circulating device is the datum.

19


Figure 5 - Schematic For Volumetric Calculations

20



Solution For 1

We can calculate the annulus volume in two ways, either by equation or table Method - By Calculation:(XSA cross sectional area) XSA of annulus =

(

π ID ca sin g

[(

4

)

2

−

(

π OD tubing 4

π ID ca sin g 2 − OD tubing 4 3.141 = 6.154 2 − 2.875 2 4 = 23.25 ins 2

=

) (

[

)

2

)] 2

]

Annulus volume = Annulus area × SSD depth ( MD ) 23.25 × 8, 210 144 = 1,325.57 ft 3 =

Annulus volume =

Note:

1,325.57 = 236 bbl 5.615

5.615 is a constant to convert cubic feet to barrels.

Method - By Table Table 3 shows data on outside tubing diameter, inside casing diameters and annular volumes. Locate for 7 inch casing that with an inside diameter of 6.154 inches. The annular volume in barrels per linear foot is 0.0288 bbl/linear ft. Annulus Volume = 0.0288 × 8, 210 = 236 bbls


21


Solution For 2

Method - By Calculation: The area corresponding to the inside of the tubing is given by: XSA =

(

π ID tubing

)

2

4

3.141 × 2.4412 = 4

4.68 × 8, 210 144 = 266.8 ft 3 =

Tubing volume =

266.8 = 47.5 bbl 5.615

Method - By Tables: Table 4 shows data outside tubing diameters and tubing capacities. Locate the tubing capacity in barrels per linear foot for 2,875 inch tubing with a weight per foot of 6.4 lbf/ft. This is 0.0058 bbl/linear foot. Tubing Volume to SSD = 0.0058 × 8, 210 = 47.6 bbl Solution For 3

Method - By Tables Total volume = (Annulus cap lin / ft + Tubing Cap lin / ft ) × depth to SSD = (0.0288 + 0.0058 ) × 8, 210 = 284 bbl

Solution For 4

Calculate the pumping time Pump Rate = 0.75 bbl/min Pump time =

22

284 = 379 minutes or 6.3 hours 0.75

REMEMBER:

Always use measured depths for volume calculations.

REMEMBER:

Always use true vertical depths for hydrostatic calculations.



Outside Casing Size OD (ins)

Wight with Coupling (lbs/ft)

Inside Diameter

Drift Diameter

Barrels for

Lin ft

(ins)

(ins)

Lin ft

per Barrel

9.50 10.50 11.60 13.50 15.10 16.60 18.80 16.00 11.50 13.00 15.00 18.00 20.30 20.80 23.20 24.20 13.00 14.00 15.00 15.50 17.00 20.00 23.00 26.00 14.00 17.00 19.50 22.50 15.00 16.00 17.00 18.00 20.00 23.00 26.00 17.00 20.00 22.00 24.00 26.00 28.00 29.00 32.00 17.00 20.00 22.00 23.00 24.00 26.00 28.00 29.00 30.00 32.00 33.70 35.00 38.00 40.00

4.090 4.052 4.0000 3.920 3.826 3.754 3.640 4.082 4.560 4.494 4.408 4.276 40184 4.156 4.044 4.000 5.044 5.012 4.974 4.950 4.892 4.778 4.670 4.548 5.290 5.190 5.090 4.990 5.524 5.500 5.450 5.424 5.352 5.240 5.140 6.135 6.049 5.989 5.921 5.855 5.791 5.761 5.675 6.538 6.456 6.398 6.366 6.336 6.276 6.214 6.184 6.154 6.094 6.048 6.004 5.920 5.836

3.965 3.927 3.875 3.795 3.701 3.629 3.515 3.957 4.435 4.369 4.283 4.151 4.059 4.031 3.919 3.875 4.919 4.887 4.849 4.825 4.767 4.653 4.545 4.423 5.165 5.065 4.965 4.865 5.399 5.375 5.325 5.299 5.227 5.115 5.015 6.010 5.924 5.864 5.796 5.730 5.666 5.636 5.550 6.413 6.331 6.273 6.241 6.211 6.151 6.089 6.059 6.029 5.969 5.923 5.879 5.795 5.711

0.0062 0.0079 0.0075 0.0069 0.0062 0.0057 0.0048 0.0082 0.0122 0.0116 0.0108 0.0097 0.0090 0.0087 0.0079 0.0075 0.0167 0.0164 0.0160 0.0158 0.0152 0.0141 0.0132 0.0121 0.0192 0.0181 0.0171 0.0162 0.216 0.0214 0.0208 0.0205 0.0198 0.186 0.0176 0.285 0.0275 0.0268 0.0260 0.0253 0.0245 0.0242 0.0233 0.0335 0.0325 0.0317 0.0313 0.0310 0.0302 0.0295 0.0291 0.0288 0.0280 0.0275 0.0270 0.0260 0.0251

121.64 126.26 133.10 144.97 161.54 176.67 206.54 122.59 82.17 86.28 92.20 102.75 111.41 114.29 127.27 133.10 59.93 61.08 62.48 63.40 65.71 70.68 76.01 82.89 52.21 55.14 58.35 61.88 46.27 46.82 48.02 48.66 50.52 53.64 56.70 35.05 36.34 37.29 38.42 39.57 40.74 41.30 43.00 29.86 30.81 31.51 31.91 32.29 33.08 33.92 34.34 34.77 35.66 36.36 37.05 38.44 39.91

4.500

4.750 5.000

5.500

5.750

6.000

6.625

7.000

Table 3 - Annular Volumes


23


Size OD (ins) 1.050 1.315

Weight With Coupling lbs/ft Non Integral Upset upset joint 1.14

1.20

1.70

1.80

2.30

2.40

2.75

2.90

1.660

1.900

2.000 2.063 3.20 2.375 4.00 4.60 5.80

4.70 5.30 5.95

2.875 6.40 8.60

6.50 7.90 8.70 9.50

11.00 11.65 3.500 7.70 9.20 10.20

9.30 10.30

12.70

12.95 15.80 16.70

4.000

9.50 11.00

4.500

12.60

13.40 22.80 12.75 13.50 15.50 16.90 19.20 21.60

1.20 1.30 1.43 1.63 1.70 2.25 2.10 2.33 3.02 2.40 2.75 3.64 3.30 2.66 3.25 3.10 3.32 4.70 5.30 5.95 6.20 7.70 4.36 4.64 6.50 7.90 8.70 8.90 9.50 10.40 10.70 11.00 5.63 7.70 9.30 10.30 12.80 12.95 13.30 15.80 16.70 17.05 9.40 11.00 11.60 13.40 12.75 13.50 15.50 19.20

Inside diameter (ins)

Drift diameter (ins)

Barrels per lin ft

lin ft per Barrel

0.824 1.125 1.097 1.065 1.049 0.957 1.140 1.380 1.278 1.650 1.610 1.500 1.670 1.813 1.751 2.125 2.107 2.041 1.995 1.939 1.867 1.853 1.703 2.579 2.563 2.441 2.323 2.259 2.243 2.195 2.151 2.091 2.065 1.995 3.188 3.068 2.992 2.922 2.764 2.750 2.764 2.548 2.480 2.440 3.548 3.476 3.428 3.340 2.780 3.958 3.920 3.826 3.754 3.640 3.500

0.730 0.955 0.955 0.955 0.955 0.848 1.286 1.286 1.184 1.516 1.516 1.406 1.576 1.656 1.656 1.901 1.901 1.947 1.901 1.845 1.773 1.759 1.609 2.485 2.347 2.347 2.229 2.165 2.149 2.101 2.057 1.997 1.971 1.901 3.3063 2.943 2.867 2.797 2.639 2.625 2.639 2.423 2.355 2.315 3.423 3.351 3.303 3.215 2.655 3.833 3.795 3.701 3.629 3.515 3.375

0.0007 0.0012 0.0012 0.0011 0.0011 0.0009 0.0019 0.0018 0.0016 0.0026 0.0025 0.0022 0.0027 0.0032 0.0030 0.0044 0.0043 0.0040 0.0039 0.0037 0.0034 0.0033 0.0028 0.0065 0.0064 0.0058 0.0052 0.0050 0.0049 0.0047 0.0045 0.0042 0.0041 0.0039 0.0099 0.0091 0.0087 0.0083 0.0074 0.0073 0.0074 0.0063 0.0060 0.0058 0.0122 0.0117 0.0114 0.0108 0.0075 0.0152 0.0149 0.0142 0.0137 0.0129 0.0119

1516.13 813.36 855.42 907.59 935.49 1124.00 517.79 540.55 630.27 378.11 397.14 457.52 369.11 313.18 335.75 227.97 231.88 247.12 258.65 273.80 295.53 299.81 354.94 154.77 156.71 172.76 190.76 201.72 204.61 213.66 222.49 235.44 241.41 258.65 101.29 109.37 114.99 120.57 134.75 136.12 134.75 158.56 167.37 172.91 81.78 85.20 87.60 92.28 133.20 65.71 66.99 70.32 73.05 77.69 84.03

Table 4 - Tubing Capacity

24



CONTENTS

1.

TYPICAL WIRELINE RIG UP

1

1.1

INTRODUCTION TO WIRELINE

2

1.2

TYPES OF WIRELINE 1.2.1 Size And Lengths Of Wire 1.2.2 Slickline Categories

2 2 3

1.3

BENDING STRESSES 1.3.1 Minimising Bending Stress

3 4

1.4

CARE OF WIRE

4

1.5

HANDLING OF WIRE

4

1.6

WIRE TESTING

5

1.7

METHOD OF WIRE SPOOLING

5

1.8

INTRODUCTION TO WIRELINE FISHING

6

1.9

BASIC TOOL STRINGS 1.9.1 Rope Socket 1.9.2 Jars 1.9.3 Spang Jars 1.9.4 Tubular Jars

9 10 11 11 11

1.10 WIRELINE STEM 1.10.1 Lead Stem 1.10.2 Roller Stem

14 14 14

1.11 QUICK LOCK SYSTEM

16

1.12 WIRELINE UNIT (WINCH)

17

1.13 POWER PACKS 1.13.1 Electrical 1.13.2 Diesel Power Packs 1.13.3 Safety Shutdown System

19 19 21 22

1.14 STUFFING BOX

23

1.15 QUICK UNIONS

24

1.16 LUBRICATORS - BLEED OFF VALVE

25

1.17 WIRELINE VALVE (BOP)

27

1.18 WEIGHT INDICATOR

30

1.19 STANDARD BRAIDED LINE RIGUP

31


i


ii

1.20 BRAIDED LINE 1.20.1 Conventional/Dyform Braided Line 1.20.2 Grease Injection System 1.20.3 Flow Tubes 1.20.4 Safety Check Union 1.20.5 Braided Line BOPs

32 32 34 37 38 39

1.21 SHEAR VALVES (TREE/STAND-ALONE)

41

1.22 WIRELINE OPERATIONAL CONSIDERATIONS 1.22.1 Previous Well History 1.22.2 Pressure Testing 1.22.3 Lubricator Fluid 1.22.4 Lubricator Equalisation 1.22.5 Setting The Stuffing Box 1.22.6 DHSV And Tree Valve Control 1.22.7 DHSV Protection 1.22.8 Tool String Weight 1.22.9 Flowing Wells 1.22.10 Checking Valves Are Clear Before Closing 1.22.11 Gas Wells 1.22.12 Floating Operations 1.22.13 Riser/Lubricator Length

42 42 42 43 43 44 44 45 45 45 46 46 47 47

1.23 EMERGENCY PROCEDURES 1.23.1 Yellow Alert (Production Shutdown) 1.23.2 Red Shutdown (Muster Stations) 1.23.3 Prepare To Abandon

48 48 48 48

1.24 SPECIFIC CONTAINMENT PROBLEMS 1.24.1 Causes of Wireline Leaks/Containment Problems 1.24.2 Stuffing Box Leak (Slickline) 1.24.3 Grease Seal Leak (Braided Cable Operations) 1.24.4 Leak In Lubricator 1.24.5 Loss Of Power 1.24.6 Broken Strand 1.24.7 Wire Birds Nest 1.24.8 Tool Stuck Across Tree 1.24.9 Broken Wire

49 49 49 50 52 53 53 55 56 57



1.

TYPICAL WIRELINE RIG UP This Rig up illustrates the various pressure control equipment and barrier classifications. (Refer to Figure 1)

Figure 1 - Typical Slickline Rig up


1


1.1

INTRODUCTION TO WIRELINE Wireline operation is a method used to lower and raise various tools and downhole controls, in and out of a production well .In addition, it is also used to set and retrieve downhole controls. The setting and retrieving operations are achieved by means of using a standard tool string which is attached to the wire. By manipulating the wire at surface the mechanical jar as part of the tool string is opened or closed to create an upward or a downward jar. These hammer actions provide the setting or retrieving of downhole controls. Wireline operation can be carried out in dead or live wells. However, it has its limitation on highly deviated wells.

1.2

TYPES OF WIRELINE Generally there are three types of wireline commonly in use: • Slickline • Braided line • Electric line. The solid single strand slick line is commonly described as: • • •

1.2.1

Piano wire Solid wire Measuring line.

Size And Lengths Of Wire The size of solid single strand slick line most commonly used are 0.092, 0.108, 0.125 inches in diameter and they are obtainable from the drawing mills in one piece standard length of 10,00 ft., 12,000 ft, 15,000 ft, 18,000 ft, 20,000 ft., and 25,000 ft.

2



1.2.2

Slickline Categories Generally there are two main types of solid single strand slick line: • •

Carbon steel Stainless steel.

Carbon Steel As the improved plow steel has high ultimate tensile strength, good ductility, and relatively low cost, it is the most popular material for carbon steel. Experience indicates that the IPS wire usually perform better than other types of wires, under the same category. IPS wire is generally used in sweet service production wells. At times some service companies may use IPS wire in H2S service wells. To protect the wire from the corrosive effects of H2S, it has to be inhibited with approved chemical. For IPS wire used in H2S service wells the maximum concentration should not be more than 30 ppm with a small percentage of CO2. Stainless Steel Due to the high H2S content of some wells special materials such as 0.108” Nitronic 50 of stainless are used. Although these are not as strong as IPS carbon steel wire they have an excellent resistance to H2S corrosion.

1.3

BENDING STRESSES Bending occurs whenever a line deviates from a straight line condition such as when it passes over pulleys (sheaves) or reel drum, or when it is flexed by hand. When carrying out wireline operations it is absolutely necessary to use specific mechanical equipment, such as the reel drum, hay pulley, stuffing box pulley and measuring wheel. Each time the line passes over a pulley it is subjected to two bending stresses when it changes from a straight to a curved path and again when it reverts to a straight line. For each trip in and out of the well the line is subjected to a minimum of 14 bending cycles: 1

When leaving the drum

2&3

Round the counter wheel

4&5

Round the hay pulley

6&7

Round the sheave

The above are repeated on the trip out of the hole.


3


If standard operational procedures are not adhered to during a wireline operation, the bending stresses that the line is subjected to may cause wire breakage. To avoid wire breakage the following recommendations should be considered: • • • • • 1.3.1

Minimise bending stresses Proper care of wire Correct handling of wire Unsatisfactory wire testing Incorrect method of wire spooling.

Minimising Bending Stress To minimise the effects of bending stresses on the wireline, approximately 50-100 ft. of wire is normally cut and discarded each time a new rope socket is made. If this is not possible, then attempt should be made at least to move the weak points to a fresh location. In addition ensure the correct size of sheaves are incorporated in the rig up for the size of wire in use. During prolonged jarring action the operation should be suspended periodically, for a certain time to cool off the line at the weak points.

1.4

CARE OF WIRE The following precautions should be taken when handling wire: • • • • •

1.5

Avoid kinking of wire To avoid abrasion wire should not be in contact with any metal surfaces Wire in storage must be regularly inspected and be adequately protected Correct procedure should be followed when spooling wire into winch reel After completion of well intervention operation wire on reel should be lubricated and protected from corrosive atmosphere.

HANDLING OF WIRE Although steel wireline has high strength to weight ratio it still requires proper handling and storage. Improve plow steel should be stored with a lubricant covering over the surface of the wire. (i.e. grease, grease paper) Un-crated wireline spools should be lifted with nylon string to avoid damage to the wire.

4



1.6

WIRE TESTING To avoid sudden breakage wireline should be regularly tested by using the torsion tester. The torsion test should be carried out at the start of any wireline operations, and thereafter every time a new rope socket is made. The number of rotations should be in accordance with the manufacturer’s guidelines. The torsion test recording should be entered into a log book along with the other wireline history.

1.7

METHOD OF WIRE SPOOLING Using correct spooling procedures can extend the lifespan of any wireline. The new wire should be spooled on to the winch drum with 250 - 400 lbs. strain on it. Five to seven bedding wraps of carefully aligned wire are recommended to provide a firm base. This also indicates during subsequent wireline operations that only a small amount of wire remains on the drum. Application of a thin coat of oil film over the wire during spooling process is highly recommended.

Figure 2 - Re-spooling


5


1.8

INTRODUCTION TO WIRELINE FISHING Fishing is the name given to the operation to retrieve items from the well which may be damaged, stuck, or have been dropped, and is an efficient way of rectifying these kind of problems. The most common reason for fishing is when a wireline has broken either at surface and remains visible or downhole and not visible. In the latter case several conditioning and preparatory trips may be necessary before the ‘fish’ can be located successfully and retrieved. As each fishing job is different these operations cannot be covered by specific procedures, but it is in this area the operator’s experience and skill can play a significant part. Wireline fishing is not a planned operation, the variety of possible fishing jobs make it impossible to obtain definitive procedures. However, it should be remembered that, standard wireline procedures and practices must still be followed wherever possible even when the rig up will almost certainly be different from normal. Fishing techniques are extremely varied and depend largely on the circumstances and well conditions for each individual situation. The following are some of the causes of a slickline fish: • • • • • • • •

6

Bending stresses Lack of control when jarring Tool string entry into lubricator Exceeding safe limits of wire strength Unclear verbal communication No proper equalisation Defective fishing neck Tools backed off.



Slickline is manufactured in a variety of sizes and materials. The common ones are shown below. Minimum Breaking Load

Nominal Diameter ins

Nominal Nett Weight per 1,000ft lbs

Rec Min Pulley Diameter ins

Bright lbf

Bridon UHT Bright lbf

0.108

31.23

13.0

2,110

2,730

0.125*

41.84

15.0

2,830

3,665

* A non-API standard size. Table 1 - Carbon Steel Wirelines To API 9a Torsion to API 9A (where applicable) Nominal Diameter ins

304 lbf

316 lbf

18/18/2 lbf

Supa 70 lbf

Supa 75 lbf

Supa 80 lbf

0.108

2,100

1,920

1,720

2,100

2,030

2,175

0.125

2,700

2,500

-

2,600

2,560

2,775

Table 2 - Minimum Breaking Load Steel

Specifications

Strength Relative To API 9A

General Corrosion Resistance Rating

Carbon steel

API 9A

API 9A

Poor

Ultra high tensile

Bridon UHT

25% higher

Poor

304 type

Bridon

API 9A

Good - not in chlorides

316 type

Bridon

10% lower

Better than 304 in very low chlorides

18/18/2

Bridon

20% lower

Better than 304 higher resistance to chlorides

Supa 70

Bridon

Similar

Good in H2S, CO2 and chlorides

Supa 75

Bridon

5% lower

Good - better than Supa 70

Supa 80

Bridon

3% higher

Good - better than Supa 75

Stainless special alloy:

Table 3 - General Comparisons Of Grades


7


The types of operation that can be performed by slickline are: •

Depth determination, although the simplest use of slickline, accuracy is perhaps no better than 20 ft at 10,000 ft. Stretch corrections are available but even these can not take into account well deviations and different well fluids. Depth control can be improved by the use of a tubing end locator and an accurate tubing tally. Another straight forward application is to check whether or not a downhole or sub sea valve is open • Checking access to the well before performing other operations, for example after running the completion to check that there is no debris and that there is no buckling or collapse • Maintaining the tubing, such as cutting wax or scale to prevent the inside diameter being reduced to the extent that access or flow is restricted • Bottom hole sampling equipment is run down to producing horizons on slickline • During tubing conveyed perforating operations, slickline can be used to detonate the guns when a mechanical bar drop firing head is being used. Slickline can also be used to release the guns after detonation using special shifting tools that lock into a mandrel above the TCP assembly • Downhole pressure gauges can be run and landed off in tubing nipple profiles or left hanging to record pressure data • Fluid interface identification in the tubing can be achieved by detecting the change in the hanging/pulling weight of the tool string which is a function of the well fluid density and the rate at which the tool string can be run into the well. This can be particularly useful for checking on the under displacement of gelled fracing treatments • Setting or retrieving devices which normally stay in the well after the wireline operation is finished, such as plugs or gas lift mandrels • Moving sliding sleeves and other devices which establish a flow path, for example from the annulus to the tubing • Bailing operations can recover produced sand and other debris from the tubing or from the sump. • Fishing for debris dropped in the well, (such as metallic parts which may have broken off the completion, wellhead, or other wireline tool), using specialised fishing tools. The setting and retrieving operations are mechanical in nature and depend on precisely machined profiles (called nipples) which are included in the completion string when it is run. These nipples are designed to catch a pre-determined part of the conveyed device and actuate it (setting). After actuation, the tool is released by jarring to break a shear pin or by the latching dogs freeing the tool once engaged into their setting profiles. There are many variations on this basic theme.

8



1.9

BASIC TOOL STRINGS The basic tool string is the name given to a standard assembly of wireline tools run into the well. The tool string is run on wireline to a specific depth to perform various tasks and retrieve by the upward movement of the wire. It is made up of a number of basic components with various other service tools attached according to the type of operation undertaken. The precise configuration of tool string will be contingent of factors such as: job type, accessibility, hole deviation, depth, pressure, completion type, log history and so on.

Figure 3 - Basic Tool String


9


1.9.1

Rope Socket The rope socket provides the means of attaching the wireline to the tool string. Various designs are available, depending on the size and type. The two most common types of rope socket in used are: • •

Conventional or knot type rope socket. Tear drop rope socket

Figure 4 - Rope Socket

10



1.9.2

Jars Jars impart a hammer action. A telescopic device permits a short amount of axial free travel, which allows the wire tension to accelerate one part of the tool while the other is stationary. Both mechanical and hydraulic jars are available. With a set of mechanical jars below the stem, the weight of the jars and stem can be used to jar up or down by pulling and then releasing the wireline. Hydraulic/spring jars are designed to provide upward jarring action in wells where it is difficult to obtain a good jarring action. Hydraulic jars are usually run just below the weighted stem and above the mechanical jars.

1.9.3

Spang Jars Spang jars are the most commonly used as they are mechanically simple, require little maintenance and can be used to jar both up and down. However, well debris can interfere with this action and their open construction can allow any wireline being fished to become entangled. Jarring force in both directions is governed by stem weight and wire speed and to a lesser extent by stroke length. However the efficiency of jarring down is restricted by the viscosity of the well fluid, the deviation and the friction of the wire. In deeper wells long stroke jars can help give a more pronounced opening and closing indication at surface. However, long stroke jars in large bore wells are prone to scissoring, i.e. the jarring force can cause the jar body to buckle outwards. In small-bore tubing the tubing walls present excessive buckling. However, in large bore tubing, the elastic limit of the jar body may be exceeded, causing permanent buckling and misalignment ‘scissoring’ of the upper and lower body parts.

1.9.4

Tubular Jars Tubular jars are commonly used when fishing for wireline. Its moving components are for the most part enclosed inside a housing, protecting it from entanglement with the wireline to be fished, and other well debris. Tubular jars have screwed components, which are susceptible to backing off during prolonged jarring. Also the efficiency of jarring down may be decreased due to the viscosity effects of the fluid displaced from inside the housing.


11


Figure 5 - Mechanical Jars

12



Figure 6 - Hydraulic Jars


13


1.10

WIRELINE STEM Wireline stem is a round solid steel rod in diameter from 1” to 21/2” and commonly 2 ft., 3 ft, and 5 ft in lengths. The stem gives weight to the tool string, and sometimes is referred to as sinker bar. Increasing stem weight increases the impact force delivered by the jars. The toolstring should not be over-weighted, as excessive mass dampens the feel and premature shearing of shear pins which are fitted to either the running or pulling tools, can occur. Flats for wrenches are provided and should be used, do not grip the tool on the fishing neck as this may damage the fishing neck shoulder. All connections should be clean and dry. Do not lubricate toolstring threads as they could back off downhole with extended periods of jarring. Threads should be checked before rig up and after use. Flaring can occur on sinker bar threads. This is indicated by the peaks of one or more threads being angled upwards rather than at right angles to the stem. It is probable they will not grip uniformly with good/bad threads and can back of very easily. Therefore, any pieces of stem with flared threads should be replaced immediately.

1.10.1

Lead Stem Lead stem provides greater weight for the same diameter and length. This stem is used primarily to run flow pressure and temperatures survey tools to obtain maximum weight with minimum cross-sectional area to protect against floating of being blown up the hole by pressure surges. Other high density, heavy weight stem available includes: tungsten, uranium, and mallory (mercury alloy) filled stem.

CAUTION: 1.10.2

DO NOT USE lead filled stem for jarring as the lead will tend to creep downwards and split the outer barrel.

Roller Stem Roller stem is often used in highly deviated wells to lesson the friction and assist tool descent. Sometimes roller stem is used in wells with paraffin, asphaltine, etc. on the tubing internal walls. It allows the stem to roll down the tubing wall, hence cutting down friction incurred when using regular stem.

CAUTION:

14

Roller and axles should be inspected for wear before use. Tools to be run should have a larger OD than the roller stem.



Figure 7 - Wireline Stem


15


1.11

QUICK LOCK SYSTEM Quick lock system tool string may be used instead of (or in conjunction with) the threaded type. The quick lock system is built into the whole range of toolstring equipment. There is no need for wrenches when making up this system. The male half is mated to the female half then rotated 90°. A spring load locking clip engages a slot and locks the assembly in place. To release the locking device it is mechanically lifted by means of a cut away window in the stem body. This system is faster and easier to make up than the thread type. It is stronger and will not accidentally back off since it does not incorporate threads. Also there are no wrench marks and hence no burrs on equipment (cutting down wear and hand injuries).

Figure 8 - Quick Lock System

16



1.12

WIRELINE UNIT (WINCH) The wireline winch has progressed from a hand operated reel driven by a belt and propelled by a pulley attached to the rear axle of a car or pick up to the present day truck/skid mounted units. Today’s wireline operations are often complex and demanding with wireline work being carried out at ever increasing depths. To meet these demands the modern wireline winch unit has been developed to provide increased power and transportability while meeting strict safety requirements. A wireline winch receives its power from a power pack and is used as the means of lowering and raising tool strings in wells that require wireline servicing. A wireline winch unit consists of the following components: • Wireline drum • Power packs • Controls. The wireline drum assembly can be single or double drum offering the facility of running two sizes of wireline from one winch unit e.g. 0.108 or 0.125 ins slickline and 3/16 ins. Braided line or 0.108 or 0.125 ins slickline and 7/32 ins mono conductor, for electric line operations. A wireline measuring head is installed as part of the unit assembly; head design will be dependent on wire diameter and type. A standard power pack supplies the hydraulic power to drive the wireline winch. The available hydraulic power supplied from the power pack must be sufficient to support the wireline operations especially when heavy jarring actions are required. The unit has to be compact for transportation and must satisfy zoning regulations. The power pack and winch may be combined into one unit or exist as separate items. Separated units use hose connections to complete the hydraulic circuit. Regardless of winch design, certain basic controls are common to all types of unit. Additional controls and instrumentation are installed to ease winch operation and will be dependent again on the type of unit used. The diesel engine of a power pack, should be regularly maintained. Silencer spark arrester should be cleaned regularly, if neglected soot may form inside the silencer and renders it unserviceable. Hydraulic filtering system must be checked and cleaned regularly. The starter motor should be either air or the hydraulic driven. The wireline winch basic control consists of: • • • • • •

Drum brake- to keep drum stationary or used when jarring Direction lever - to select rotation direction of drum Gear box - to select speed of drum rotation (usually four gears) Hydraulic control valve (double ‘A’ valve) to control speed of drum rotation Weight indicator- to measure strain on wireline Odometer - to indicate wireline depth.


17


Figure 9 - Double Drum Wireline Unit

18



1.13

POWER PACKS

1.13.1

Electrical The power pack discussed in this section is the Zone 1, 75 HP electric/hydraulic type. This power pack is an all steel construction skid mounted unit with detachable crash frame. Four lifting points are provided with a safe working load of 2 tons. The heavy duty frame is fitted with removable protection side panels for easy access and maintenance. Most operators use diesel power packs but electrical power packs are used in some areas. Electrical power packs are required to be intrinsically safe (i.e. spark proof) and can be used in Zone 1 operations. Zone 1 is an area around the wellhead, which is restricted to intrinsically safe equipment. Electrical power packs are simple to operate and maintain. However care must be taken to ensure that the power pack is connected to the correct power source. When the power pack has been connected the direction in which the motor is running must be checked. Little maintenance is required on electrical power packs. The hydraulic oil and the suction strainer must be checked regularly. Hydraulic Operation The EXD electric motor drives an Abex Denison double vane pump, delivery at setting of 1,760 rpm. 32 imperial gallons minimum at P1 (wireline unit draw works supply) and 6.5 gallons per minute at P2 (re-spooling cat head or auxiliary equipment supply). The pump has two relief valves P1 set at 2,200 psi and P2 set at 2,000 psi. A suction stop valve is provided to isolate the hydraulic oil reservoir when servicing pump etc. Relief valve P2 is fitted with a vent valve to allow the low volume section of the pump to be unloaded when not in use. Hydraulic oil cooling is by the return oil heat exchanger installed at the rear of the electric motor. Air is drawn through the oil cooler by the motor blower fan. A 70 gallon hydraulic reservoir fitted with filler/breather and fluid level gauges. The 125 micron suction strainer is located within the hydraulic oil reservoir. The return fluid is through a 25 micron filter. Operation and Maintenance Electric power packs are very simple to operate. However, care must be taken to ensure that the power pack is connected to the correct power source. When the power pack has been connected the direction in which the motor is running must be checked.

NOTE:


Before starting the electric pump, the hydraulic system must be looped or connected to the wireline unit.

19


Figure 10 - Electric Power Pack

20



1.13.2

Diesel Power Packs Diesel engines are used because they are more reliable than petrol. They can be made to function more safely in hydrocarbon hazardous areas (no spark plugs, contact breakers, distributors etc) and the exhaust can be fitted with an efficient spark arrestor. Also diesel fuel is widely available offshore whereas petrol is normally not allowed. Diesels engines are simple in design; they require only fuel and compression to operate.

Figure 11 - Diesel Power Pack


21


1.13.3

Safety Shutdown System Under normal operating conditions, engine oil pressure is supplied to the following equipment: • • • • •

Over speed valve Exhaust temperature valve Fuel shut off valve Control cylinder Water temperature valve.

If oil pressure is lost, or seriously reduced, the fuel shut off valve and air intake ‘D’ valve closes, thus stopping the engine. Oil pressure losses at the fuel shut off valve can be caused by any of the following: • • • • • •

Shortage of engine oil Damaged or broken oil line Oil pump failure High exhaust gas temperature causing valve to open, thus dumping oil High water temperature causing valve to open, thus dumping oil to sump Engine over revving causing over-speed to dump oil to sump.

If the engine is over speeding due to incorrect operator control or to flammable gas entering the inlet manifold, the ‘D’ valve will close off the inlet preventing further entry of gas.

NOTE:

Even if the fuel is shut off, the engine could continue to run on the flammable gas entering the inlet manifold if the inlet manifold is not closed off.

The diesel engine of a diesel power pack, should be regularly maintained. Exhaust/spark arrester should be cleaned regularly, (if neglected, soot may form and render it ineffective). Hydraulic filtering systems must be checked and cleaned regularly. Starter motor should be either air or hydraulically driven. The power pack requires to be positioned and operated only in areas designated as safe, in accordance with IP ‘model code of safe practise in the petroleum industry’ which classifies areas as: Zone 0 Zone 1 Zone 2

22

In which flammable atmosphere is continuously present or present for long periods (More than 1,000 hours per year). In which a flammable atmosphere is likely to occur in normal operation (About 10 to 1,000 hours per year). In which a flammable atmosphere is not likely to occur in normal operation, and if it occurs will exist only for a short period (less than 10 hours per year).



1.14

STUFFING BOX A wireline stuffing box is used when it is necessary to perform slickline work on a live well. It has different purposes for slickline and braided line: (Refer to Figure 12 for slickline, braided line will be discussed later). The stuffing box consists of a packing chamber, containing short doughnut-shaped rubber sleeves bored for the diameter of the wire, with an external adjustable nut. For slickline, the nut is sufficiently tightened to compress the rubber packing around the wire, to minimise leakage, while allowing the wire to move freely. Stuffing boxes are available with hydraulic packing nut assemblies, designed mainly for H2S service, where the packings can be tightened remotely without the danger of personnel being exposed to the leaking gas or where access to the stuffing box is difficult. For low pressure operations common designs utilise a blow out plug with blow out plug retainer. For higher pressure an inbuilt ball and seat provide shut off in the event of a line breakage. The highpressure designs often include an integral injection point and check valve to facilitate injection of inhibitors, lubricants or methanol to prevent hydrate formation for braided line stuffing boxes.

Figure 12 - Hydraulic Stuffing Box


23


1.15

QUICK UNIONS The connections used to assemble the lubricator and related equipment are referred to as quick unions. They are designed to be quickly and easily connected by hand. Quick unions are the weakest link in a pressure control equipment rig up, and they will determine the overall pressure ratings of the rig up. The box end receives the pin end which carries a ‘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.

WARNING:

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, make sure that tugger lines and hoists are properly placed to lift the lubricator assembly directly over the wellhead.

Figure 13 - Quick Unions

24



1.16

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, date and rating of last hydrostatic test. 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 obtain the desired length. 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, there by requiring only tightening by hand. 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. Some companies implement a colour coding system. The colour coding system uses one or two bands of colour to identify the service. 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

Colour

3,000 psi

Red

5,000 psi

Dark green

10,000 psi

White

15,000 psi

Yellow

Table 4 - Colour Coding And Pressure Rating of Pressure Control Equipment


25


Figure 14 - Lubricator

26



1.17

WIRELINE VALVE (BOP) The wireline BOP has movable rams with shaped rubber elements and is used to close and seal on the wire without damaging it. This allows well bore pressure to be contained underneath while depressurising above. The rams can be manually or hydraulically actuated. Manual

Operated by manually turning the two handles to open and close the rams. Manual BOPs are used primarily for low pressure non-gas service

Hydraulic

Operated by a hydraulic pump, but with a manual backup. A hydraulic BOP can be closed manually but must be opened hydraulically after the stems have been back out manually, care must be taken to ensure hydraulic pressure is kept to a minimum.

Hydraulically actuated wireline valves are more commonly used because of quick response closure time and ease of operation. A wireline valve is usually installed between the wellhead /Xmas Tree and wireline lubricator. Wireline valves are fitted with equalising valves that allow well pressure to be equalised across the closed rams assembly, prior to opening. Without this, if the valve rams were to be opened without first equalising the pressure surge could blow the tool string or wire into the top of the lubricator, causing damage or breakage. Since the wireline valves are such a vital component to control the safety of the well it is important that these valves are regularly pressure tested. The purpose of using wireline valves is as follows: • • •

To enable well pressure to be isolated from the lubricator when leaks develop etc To permit assembly of a wireline cutter or cutter bar To permit stripping of wire through closed ram when recovering broken wire from a live well. To avoid damage or cut the wire correct size of wire guides should be used to guide the wire when closing the rams. Wireline valves will hold pressure from below only. Ram type wireline valves are designed to seal the wire when not in motion. Ram type wireline valves are self actuating. Once an initial seal is established on closing, the difference in pressure above and below the rams assist the sealing action. The seals are arranged so that the pressure differential forces the rams together and upwards.


27


Figure 15 - Hydraulic BOP Single

28



Figure 16 - Manual BOP


29


1.18

WEIGHT INDICATOR The primary function of the weight indicator is to measure the degree of tension on the wireline. It is essential that the weight indicator be monitored continuously during wireline operations in order to prevent overloading of the wireline. In addition the weight indicator will also show any changes affected by hole conditions. A load cell or strain gauge, which is usually fitted as part of the rig up, measures the wireline tension or total loading on the wireline. As the load sensor is designed and calibrated for a 90° angle, it is important that the angle of the hay pulley be positioned at this angle. There are three main types of weight indicator: Mechanical This type of weight indicator is not very often in use. It is suitable only for 0.072” wireline and the basic design combines measuring wheel. Hydraulic

This unit is incorporated with a load cell, gauge, and signal hose. The highpressure hydraulic hose is connected from the load cell to the weight indicator located in the winch instrument panel. Any weight variation is transmitted to the weight indicator via the hydraulic hose. A damper is provided to adjust the required sensitivity and minimise any erratic movement. The hydraulic weight indicator has been field proven and is very frequently used through out the industry. It requires very little management.

Electric

This unit has a sensing element similar to the hydraulic unit. Line pull is however, transmitted via a potentiometer and a 2 conductor cable to the meter read out. This instrument is delicate and requires careful handling to maintain the sensitivity and accuracy.

Figure 17 - Load / Weight Indicator

30



1.19

STANDARD BRAIDED LINE RIGUP This rig up illustrates the relevant pressure control equipment and barrier classifications. (Refer to Figure 18)

Figure 18 - Typical Braided Line Rig up


31


1.20

BRAIDED LINE The most often used brained line is 3/16” or 15/32” cable comprising 16 (9 + 6 + 1) strands. The core and the right-lay inner wires are thinner than the left-lay outer wires. By using right and left lay the twisting tendency of the wire under load is minimised. The breaking strength of 3/16” wire is approximately 4,500 lbs (2,000 Dan), giving a safe working tension of about 3,500 lbs (1,550 Dan). Braided lines with no internal conductor are called sand lines and a rig usually has one on a special winch used for fishing etc. They are much stronger than electric line, usually at least double the breaking strength.

1.20.1

Conventional/Dyform Braided Line The conventional cable comprises 16 (9 + 6 +1) strands. The core and the right lay inner wires are thinner than the left lay outer wires. By using right and left lay the twisting tendency of the wire under load is prevented.

Size Dia (ins)

Minimum Breaking Load

Flow Tube Bore (ins)

Weight (lbs/1,000 ft)

Rec Min Pulley Dia (ins)

Galvanised (lbs)

316 Stainless Steel (lbs)

Supa 60 (lbs)

Supa 70 /Supa 75 (lbs)

3

/16

0.196

71.1

12

4,960

3,990

3,680

4,320

7

/32

0.228

95.9

14

6,610

5,400

4,960

5,842

1

0.261

125.5

16

8,640

7,030

6,480

7,600

3

0.327

195.9

20

13,490

11,000

10,120

11,660

/4 /4

Table 5 - Relative Strengths of Various Conventional Braided Wireline Sizes Some time ago Bridon introduced Dyform cable. Around the single centre core are nine thinner right-lay wires.The outer wires are also right lay, but thicker. The finished cable is pulled through a die. By doing so, the following improvements are made: 20% increased in breaking load, because there is more steel in the same diameter. Smooth external periphery and closer tolerance of outside diameter, reducing leakage at the stuffing box. Higher crush resistance because of the increased steel content of the cable. Low twist tendency because of the Dyform Process. Table 6 gives wireline date relating to Dyform braided line. Size Dia (ins)

Flow Tube Bore (ins)

Weight (lbs/1,000 ft)

Rec Min Pulley Dia (ins)

Minimum Breaking Load Galvanised (lbs)

316 Stainless Steel (lbs)

Supa 60 (lbs)

Supa 70 /Supa 75 (lbs)

3

/16

0.196

85.21

12

6,170

4,930

4,560

4,960

7

/32

0.228

111.4

14

8,370

6,500

5,990

5,990

1

0.263

147.6

16

11,200

8,640

7,830

8,530

3

0.330

231.5

20

17,540

13,550

12,080

13,380

/4 /4

Table 6 - Relative Strengths of Various Dyform Braided Wireline Sizes

32



Figure 19 - Component Strands of Conventional Braided Line

Figure 20 - Component Strands of Dyform Cable


33


1.20.2

Grease Injection System In wireline operations where braided line is being used, or in slickline operations where high wellhead pressure or gas exists, a grease injection system is required in order to effect a complete seal around the wire. The grease injections head assembly consists of flow tubes providing a close fit around the line, usually to within 0.004” diameter when both cable and tubes are new. Viscous grease is pumped in at the joint at the top of the bottom tube through the grease inlet hose into the small annulus between the flow tube ID and the cable. Note that this clearance will usually be greater than this, and can be much as 0.025” without affecting performance in an oil well. The tolerance in gas well situations should be towards the lower end of the scale. As a new wire is broken in, it is said to season. This means that it becomes impregnated with grease and makes a more reliable seal easier and faster running speeds possible. However during seasoning, cable also gets thinner and longer, increasing the tolerance, and this will also increase due to differences in tension, e.g., running in/pulling out. As a cable ages it wears and stretches, causing it to thin. Different ID components are available to take account of this, and must be correctly matched to the measure cable diameter. The number of flow tubes and flow tune sleeves used, depends on the well pressure: • • •

2 Flow tubes 3 Flow tubes 4 Flow tubes

0 - 2,000 psi 2,000 - 10,000 psi 10,000 - 15,000 psi.

Concentric Flow Tubes Instead of wear inserts, this type of tube is in the form of a replaceable internal part, surrounded by a concentric external load-bearing tube. This flow tube provides a much closer fit on the cable all along its length and is therefore more efficient than solid type. Three tubes will provide a seal at 10,000 psi, making the grease injection head shorter. This can be important in situations where clearance is limited, e.g. when working on the production deck. Another method of reducing the overall length of the lubricator is to include a device called a ‘turn around sub’. This is essentially a pressured sheave assembly which is inserted at the top of the ball valve. It turns the injection assembly through 180° so that it points down, not up. 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.

34



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. 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 described below: a)

Grease system The system pump draws grease from the grease reservoir through the pump section 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. 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 size flow tubes.

NOTE: b)

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.

Pneumatics The driver 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 valve. Position one is where the supply is blocked with the reservoir vented to atmosphere. Position two is where the supply 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.

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).


35


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.

Figure 21 - Grease Injection Head

36



1.20.3

Flow Tubes A range of flow tubes, 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 ins to 0.006 ins 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 in the outer strands gradually holds them back with regard to the inner strand 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 22 - Flow Tubes


37


1.20.4

Safety Check Union This device is normally included in stranded wireline lubricator hook-ups just below the grease injection head. The wire is threaded through both these units and if the wire breaks and is blown out of the grease injection head, the well pressure is 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. Well pressure holds the ball against the seat. This device does in fact fulfil the same function as the internal BOP in the solid wireline stuffing box. As with all lubricator equipment, this safety check union is furnished with quick unions.

Figure 23 - Safety Check Union

38



1.20.5

Braided Line BOPs Ram type BOPs are self-actuating. Once an initial seal is established in closing the difference in pressure above and below the rams assists the sealing action. The seals are arranged so that the pressure differential forces the rams together and upwards. (Refer to Figure 24) This means that: • • •

The sealing force is independent of the closing force after the seal is established The ram sealing action is directional The pressure must be equalised before opening.

Ram type BOPs are designed to seal with the cable static, and all cable movement should be stopped before closing the rams. Braided line dual ram BOPs are configured with the lower set of rams inverted, and with a grease injection port in between the rams. This allows the two sets of rams to trap a cavity full of grease between them of higher pressure, preventing escape up or down. This is mandatory in gas wells since gas will migrate up the cable between the inner and outer armour. By filling the cavity at a pressure higher than wellhead pressure, the grease fills the spaces and prevents escape. Dual ram BOPs are normally integral, but they may be made up, by stacking two single BOPs on top of each other. A typical braided line rig up is shown in Figure 25

Figure 24 - Braided Line Dual Hydraulic BOP


39


Figure 25 - Braided Line Rig up

40



1.21

SHEAR VALVES (TREE/STAND-ALONE) During wireline operations it may become necessary to cut the wire, and a choice of valves are available to do this. Some Xmas Tree valves are designed to do this without damaging the valve. In some cases, e.g. when fishing with heavy duty wire, it may not be advisable to do so. In such case, it may be necessary to include a purpose designed shear valve, mounted just above the tree. This is a ram type shear/seal BOP because of its superior cut capacity. The valve should cut the wire or the BHA. It has the additional advantage of sealing at the bottom of the riser.

Figure 26 - Shear Valves Shear valves should be considered when: • • •

The DHSV is locked permanently open using a sleeve. This means that it cannot be used as a barrier with the wireline out of the well The lubricator is not long enough to contain the whole tool string. If the Xmas Tree valves leak, the lubricator could not be isolated otherwise An extra barrier is required due to the nature of the operation, or the equipment configuration.


41


1.22

WIRELINE OPERATIONAL CONSIDERATIONS

1.22.1

Previous Well History Prior to commencing any braided line operations on a well, it is prudent to check the well file for any previous problems that may have been encountered (most operators keep a problem database for each well). A well schematic showing depths of nipples, gas lift valves, sliding sleeves etc., is an essential item for the braided line operator. When the duration of braided line operations necessitates a change of personnel at the end of a shift it is important that a comprehensive handover is conducted between the crew going off shift and those coming on. Information as to the status of the job, problems encountered, and the current tool string configuration should be included.

1.22.2

Pressure Testing Each time the tool string is loaded into the lubricator the system should be pressure tested prior to opening up the well and running in hole. The test value should be decided beforehand, and would commonly be 110% of SIWHP, rather than design pressure. It is unnecessary to test to several thousand psi when the SIWHP of a depleted reservoir may only be a few hundred psi. A typical test will consist of pressuring up the lubricator (and riser, if used) against the closed tree swab valve, to the working pressure of the lowest pressure rated item of equipment in the rig up. It is important to ensure as much air is bled from the system as possible, in order to obtain a satisfactory pressure trace on the chart recorder. Water or other suitable liquid should be used. When using braided line, to achieve this: • •

•

Pump at a sufficient rate to vent air via the grease injection head. Cement or other high-capacity pumps might be used to speed this up As the liquid begins to leak out at the grease injection head slow the pump rate down and increase the grease injection pressure to effect a seal (if pump rate is not reduced, grease may be stripped through the flow tube too quickly and a seal will not be achieved) Continue to pressure up with the test pump and hold stabilised pressure for the prescribed time.

The grease injection system should always be pressure tested to its maximum, irrespective of the well pressure expected.

42



When using slickline: • • •

1.22.3

While pumping, vent air through lubricator bleed off line When water appears at bleed off line reduce pump rate and close in needle valve Continue to pressure up with the test pump and hold stabilised pressure for the prescribed time.

Lubricator Fluid When conducting wireline operations on gas wells or high GOR oil wells it is important that the fluid used to pressure test the lubricator is inhibited, to prevent the formation of hydrate plugs around the wellhead. Typically, a mixture of glycol and water is used. Normally the pressure testing fluid falls down the well and consequently consideration should be given to ensure that the fluid is chemically compatible with the formation. Small concentrations may also enter the process facilities when conducting cleanup flows. It may not be advisable or advantageous to allow the riser contents to enter the well after pressure testing, and in this case the riser/lubricator will need to be evacuated of pressure test fluid (and possibly the test fluid saved for re-use), at the surface prior to running in the hole. The BOP/riser manifold has to be made up to enable this.

1.22.4

Lubricator Equalisation Prior to opening the tree valves it is important to ensure that the pressure in the lubricator is approximately equal to, or slightly above, the SIWHP. This is to: • •

Reduce the chance of damaging the valve seals by opening them against a differential Reduce the chance of differential surges jerking and damaging the tool or wire.

Pressure gauges should be positioned in the following places: • • •

Above the wireline BOP to monitor lubricator pressure Below the wireline BOP to provide BOP differential pressure On the tree to monitor SIWHP.

A convenient procedure is to bleed the lubricator pressure down, after completion of a satisfactory pressure test, to ± 100 psi above the SIWHP. This small pressure differential will not damage the valves and it will serve as an indication that the valves have opened and the pressure has equalised correctly. Difficulty in opening valves could indicate that pressure has not been equalised correctly. When RIH the tree valve opening sequence should be: 1.

Hydraulic master valve (HMV)

2.

Swab valve.


43


So that the HMV does not have a differential pressure across it when opening, when pulling out the shut-in sequence should be: 1.

Swab valve

2.

HMV

Check that the correct number of turns have been used to open and close the swab valve. 1.22.5

Setting The Stuffing Box During slickline operations, the stuffing box needs to provide a leak tight seal around the wire while still allowing the wire to move. However the stuffing box should not be over tightened, since: • • • •

This causes excessive packing wear More weight needs to be used to overcome the extra friction The extra weight brings line tensions closer to limits The tool string is lengthened, requiring a longer lubricator.

On high wellhead pressure wells, note that extra stem is required not only to overcome the extra upwards force on the cable, but to overcome the extra stuffing box friction. 1.22.6

DHSV And Tree Valve Control During wireline operations, the normal tree valve control system is overridden and operation of the valves is achieved through a separate bypass control unit. This ensures that valves are not accidentally closed by the process control ESDs, etc. while wireline is in the hole. This unit should not be placed in the wellbay area, unless it is permanently manned by someone in adequate communication with the wireline operator/supervisor. It may have mimic controls placed in safe position for emergency use. Ideally it should be available to the person in charge of the wireline operation who has a clear view of the ongoing job and other activities taking place on the installation, e.g. crane operations, etc. When conducting wireline operations below the DHSV, the control line can be closed in at the Xmas Tree, to lock in pressure, ensuring that the valve cannot be accidentally closed on the cable. Closing the valve on the cable if it is of the flapper type will not necessarily part the cable but will almost certainly damage the valve seat. This is recommended if the bypass control does not have a hydraulic accumulator feed. The closing pressure should be continuously monitored downstream of the shut-in valve to ensure that slow leaks do not lead to accidental valve closure. For this reason, pressure regulator systems connected to accumulators are preferred to hand pumps. Removing a DHSV can permit the well fluids access to the control line. In the case of unexpected pressure in the well, a build-up can escape via this line. This can cause: • •

External leaks Pressurisation of components and hydraulic oil reservoirs beyond their rating.

DHSV control lines should therefore always be fitted with a manual block valve close to the tree, which should be closed immediately prior to DHSV removal.

44



1.22.7

DHSV Protection If the well contains a wireline retrievable DHSV, the valve may have to be pulled in order to provide access for the tool string. Protection sleeves are available for setting in the DHSV landing nipple that prevent damage of the seal bore by wireline cutting. Tubing retrievable valves can also be locked out during wireline operations. If the operator chooses to lock the DHSV open then they must ensure that two mechanical barriers are available to shut in above it, i.e. master valve and swab valve. When wireline is in the well in the hole below the DHSV, it is not normally considered to be a barrier, whether or not it is capable of cutting the wire.

1.22.8

Tool String Weight The weight of the tool string should be tailored to the specific requirements of the operation to be undertaken. Weight should be increased to: • • •

Overcome sealing assembly friction and well pressure on the cross-sectional area of the wireline Ensure sufficient weight to provide required jarring force Ensure sufficient weight to keep tool string stationary if flowing the well for logging purposes.

Adjusting the tool string weight is simply achieved by adding or removing lengths of stem. However there are limits to the amount of weight that can be added because of: • Tool length limit • Riser length limit. • Downhole pick-up weight constraints (cable strength limit). For a standard 15/32” (0.221”) braided line, each 1,000 psi wellhead pressure will require approximately 40 lbs weight to overcome, and add 3 ft length to the tool string. 1.22.9

Flowing Wells Flowing the well with tools in the hole is carried out when: • •

Production logging (braided line) Conducting pressure/temperature/gradient/PLT surveys. (slickline)

The main area of concern is in preventing the tools from being carried up the hole by the force of the wellbore fluid, with the potential for the tools to overtake the wire and become stuck, or the cable produced through the flow line. • • • •

Ensure sufficient tool string weight Open well slowly, after positioning the tool string below the fluid level Determine whether the tool string may be pulled into the tubing shoe or not. If not, make sure that depth upper and lower limits (which take account of the tool length) are set and observed Exercise caution if pulling tools through restrictions or gas lift valves.


45


When conducting slickline logging it is sometimes difficult to detect a loss in weight on the weight indicator if the tool string is being pushed up the well by the producing fluid. With braided line the tool position can be monitored by means of the CCL to give a positive indication of movement. The required tool string weight should be estimated during pre-job planning to determine if well flowing conditions will impede the tool string descent. Most service companies have software packages to calculate flowing conditions and alter tool string design accordingly. When pulling plugs, etc. it is important to ensure that the device is equalised, i.e. has the same pressure above and below. If the pressure above is too high, it may be impossible to pull the prong/device, perhaps eventually leading to a broken wire. If the pressure below is too high, the surge may cause the prong/device to be blown up the well, also leading to tangling and possibly broken wire. 1.22.10 Checking Valves Are Clear Before Closing Prior to commencing wireline operations on a platform or land based rig up, it is important to check the number of turns required to fully open, and close both the swab and master valves on the tree. This will serve as an indication as to whether the tool string has completely cleared the valves and is totally into the lubricator before opening up the riser to lay down the tools. Some manufacturers provide ‘tool in riser’ indicator devices. 1.22.11 Gas Wells During braided line operations in gas wells, if the seal is lost it will prove harder to re-establish because: • • •

The increased volume of gas compared to oil will tend to strip the grease out of the flow tube Lube oil based grease becomes contaminated and thins (loses viscosity) The cooling effect of gas escape thickens the grease.

Careful selection of grease type and the number and diameter of flow tubes required is important to minimise the chance of a leak. The ambient temperature has an important effect, and the grease selected must retain its properties at low temperatures. The use of synthetic greases (usually silicon-based) is sometimes necessary, despite its cost.

NOTE:

Grease cannot be re-used.

When conducting wireline operations on gas wells the following additional points should be noted: •

46

The probability of hydrate formation is much increased in comparison to oil wells. Monitor line tension closely when pulling tools through tree valves in case hydrate plugs have formed, causing a restriction in ID.



•

• • •

Alertness to steps in the OD of braided line is critical in gas well operations. Because the seal in gas is much more sensitive to clearance, the flow tube assembly will only effect a good seal around a constant cable OD. Steps typically occur when a cable used often at the same depth is used in a deeper well for the first time. Turning the cable round on the drum aggravates the problem, e.g. the tool is difficult to get down at surface (least weight on cable) and leaks occur at the thinner section of cable (tool downhole). Twin BOPs should always be used, with the bottom pair inverted to allow for the injection of grease between the two. All ‘O’ ring seals and BOP seal elements etc. should be compatible with the well fluids. The injection grease can be doped with H2S inhibitor if required.

1.22.12 Floating Operations Floating operations may require to have wave motion compensation, and usually the rig compensator is used. Note that if the unit is far enough away from the rig floor, hanging the sheave/pulley directly on the top of the lubricator may be sufficient. If not, compensation is achieved by hanging the upper sheave on the travelling block, and utilising the rig drilling compensator. Since the compensation systems works by moving the sheave up and down, it must only be activated when the tool string has been run some distance into the well.

NOTE:

That the construction of braided line means that some gas migration is possible through the core, even though the grease seal equipment is functioning perfectly.

1.22.13 Riser/Lubricator Length If both the riser and lubricator are used to contain the tool string, there is no way to close the well in the case that the tree valves leak. In this case the use of a shear/seal valve above the tree should be seriously considered. However, in general this configuration is not recommended. Operations should be planned to contain the complete tool string above the riser within the lubricator only. If on a drilling rig, there should be plenty of space in the derrick to assemble a lubricator of at least 80 ft, long enough for most tool strings. If on a satellite wellhead, the crane boom is normally long enough to provide a similar clearance.


47


1.23

EMERGENCY PROCEDURES

1.23.1

Yellow Alert (Production Shutdown) Although the shut down is not necessarily directly related to the wireline operation, the alert may escalate. The following actions should be taken immediately, presuming that the situation might deteriorate: • • •

If close to the surface, move the wireline so that the tool string is not across the tree Apply winch brakes and shut down the wireline unit power pack If necessary close the stuffing box, since it is harder to seal on a cable which is stationary (braided line).

If the tool string is in the lubricator: • •

Close the upper master valve Then close the swab valve, then bleed down lubricator pressure, or

If the tool string is below the Xmas tree: • • • 1.23.2

Red Shutdown (Muster Stations) • • •

1.23.3

Proceed as per yellow shutdown (there is no need to hand back permit) If directed, essential personnel should stay with unit Other personnel should proceed to muster stations.

Prepare To Abandon • •

NOTE:

•

48

Close the BOPs Check that the well has been made safe as per permit stipulations Return work permit.

If the tool string is in the lubricator, check that the upper master valve, the swab valve and if possible the DHSV are closed If the tool string is below the Xmas tree, cut the wireline using the correct valve.

That tree valve are not always able (or designed) to cut the wire, and the valve to be used for this should be determined before the job. Then close the tree valves as above All personnel to proceed to muster stations or lifeboats as directed.



1.24

SPECIFIC CONTAINMENT PROBLEMS

1.24.1

Causes of Wireline Leaks/Containment Problems MAJOR LEAKS • • • • •

Due to main sealing device failure Due to freezing rendering sealing devices inoperative Due to absence of cable Due to elastomer seal failure Due to riser/lubricator mechanical failure.

MINOR LEAKS • • •

In gas wells In sour gas Thru closed BOPs.

OPERATING PROBLEMS LEADING TO LEAKS • •

Fragile cable breaking/stranding Air/grease supply failure.

WELL KILL SITUATION • • 1.24.2

Tubing blocked by wireline Secondary well control device failure (e.g. BOPs).

Stuffing Box Leak (Slickline) Hydrocarbons escaping from the stuffing box during slickline operations are predominantly caused by packing wear. This should be quite an unusual situation, and is easily avoided by: • •

Correct packing nut setting (not over tightened) Regular inspection of stuffing box packing and changing as required, e.g. every time wire is cut back.

The packing nut compression is usually a small fraction of the maximum available. Leaks are most often cured, by simply increasing the compression accordingly. However, a rough or corroded cable can sometimes lead to excessive wear. If tightening the packing nut does not cure the leak at that point, particularly in oil wells at moderate pressures, small leaks may be acceptable in order to pull out of hole and make repairs. Alternatively, it may be acceptable to close one set of BOPs and strip through them.


49


Otherwise, the stuffing box will have to be repaired by replacing the packing. Normally this repair is made by cutting the wire. To do this: 1.

If possible stop cable movement immediately or move tool string to a position where the cable can be held stationary

2.

Close both sets of wireline BOPs and bleed down lubricator pressure

3.

Inflow test BOPs to ensure they are sealing. This is done by observing that the lubricator pressure stays at zero after closing the bleed valves after bleeding down

4.

Open the bleed screw in the stuffing box to ensure that no pressure remains

5.

Unscrew the gland nut completely to expose the packing elements

6.

Clamp and cut the wire

7.

Withdraw the packing elements and remove them from the wire

8.

Ream the new packing element with a piece of scored wire and place them on the wire

9.

Rejoin the wire.

Normally in slickline operations it is perfectly acceptable to cut the wire, however there may be a reason not to do so. In this case, a temporary repair may be made by splitting the packings with a knife to allow them to be placed on the line without cutting it. Before pushing the new elements into the stuffing box it is essential to rotate each packing element to ensure that the diagonal splits do not line up. This will prevent selective wear and a keyseat appearing on one side of the packing. This should be considered a last resort emergency measure only, and this temporary packing should be changed as soon as the tool is retrieved. 1.24.3

Grease Seal Leak (Braided Cable Operations) A leak past the grease injection head is a common occurrence, and is usually associated with a lack of grease pressure. Normally this is due to simple operational factors which can be easily prevented and remedied: • • • • • •

Pulling out (or running in) too fast, particularly on the first run (dry cable) Setting the grease injection pressure too low An increase in wellhead pressure, e.g. after perforating Not enough grease in the supply tank Restrictions in the grease supply system Low grease pump air supply pressure.

However a leak could also be as a result of one or a combination of the following factors, with potentially more serious consequences: • • • •

50

Grease type incompatible with conditions, e.g. ambient temperature or freezing due to gas escape Contaminated grease becoming thinner Incorrect flow tube insert ID or worn flow tubes Insufficient flow tube length.



Leaks are potentially serious in gas wells. If acted upon early enough, it may be possible to reestablish the grease seal in the following ways.

NOTE: • •

That the time available is short in gas wells and contingency plans should be well developed for this: Increase grease injection pressure RIH slowly to: 1. Help the grease flow into the well rather than out 2. Pass a well-greased section of wire through the flow tubes.

In oil wells, this is normally sufficient to re-establish the seal, or slow it sufficiently to retrieve the tool and reconfigure or repair the seal assembly. The stuffing box may be used to slow the leak and help the grease seal re-establish itself.

NOTE:

• • • •

That when the stuffing box is closed, flowing well fluid may be diverted down the grease return hose, and it should be securely tied down before the job. In this case: Stop all cable movement Close stuffing box Close the valve at the end of the grease return line Once the leak has been contained, re-open the grease return line and allow grease to circulate before continuing the operation.

Do not close the grease return line valve first, as this requires the stuffing box to close against a higher initial pressure. In gas wells, this may not be sufficient. Before any corrective measures are taken, the escaping gas must be immediately brought under control to prevent freeze-up and hydrate formation. This is done by: •

Stopping cable movement immediately if possible, or move tool string to a position where the cable can hold stationary • Close both sets of wireline BOPs, inject grease between them and bleed down lubricator pressure • Once the escape is stabilised, a number of corrective steps can be taken in an attempt to re-establish the grease seal. These are: 1. Wait for the freeze up to thaw, or assist with a steam hose. 2. Pump heavy oil first to re-establish grease circulation. 3. Circulate grease for some time to remove all thin grease or oil remains. 4. Change grease type if possible. At the same time the pressure and volume capability of the grease system should be verified. Because the ID of high-pressure grease hoses is so small, quite modest restrictions can cause considerable pressure losses.


51


If none of the above actions helps to abate the leak the cable may have to be cut to allow the seal assembly to be inspected and repaired/reconfigured. There are a number of possibilities which become possible once the cable has been cut: • Worn flow tubes replaced, or smaller ID inserts used • More flow tubes added • Additional grease injection points added. The procedure for cutting the cable is as given below.

NOTE

That a knotted cable cannot be pulled over sheaves, and that the operation is considerably speeded up if the cut and knot is made far away from the top of the lubricator at the winch drum after slacking some cable:

•

If possible stop cable movement immediately or move tool string to a position where the cable can remain stationary Close both sets of wireline BOPs and bleed down lubricator pressure Inflow test BOPs to ensure they are sealing Disconnect lubricator and secure wire above BOPs with fishing clamp Pull a few wraps a wire off cable drum and cut wire close to winch unit, pull wire out of stuffing box and grease seal assembly Make the necessary inspection and or/adjustments to the sealing assembly Rethread wire through stuffing box and knot free end at winch unit, spool loose wire back onto drum Remove fishing clamp and reconnect lubricator Equalise pressure and open BOPs Pull out of hole and replace knotted section of wire if sufficient is remaining on drum.

• • • • • • • • •

1.24.4

Leak In Lubricator Although the lubricator will have been pressure tested prior to commencing operations, the action of jarring etc. can induce bending in the lubricator and hence cause leaks at the connections probably as a result of ‘O’ ring failure. It is good practice to visually inspect and replace the ‘O’ ring at the connection used every time the lubricator is broken open. It may be sufficient to remove the damaged ‘O’ ring, split a new one diagonally with a knife, place over the cable, join it with a proprietary adhesive available from seal manufacturers then place in the groove. If this does not work and it proves necessary to replace with an uncut seal, then the procedure for cutting and re-splicing the line is as per 1.24.2

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1.24.5

Loss Of Power In the event that the power pack fails: • • • •

1.24.6

Clamp wire at the vertical section close to the lower sheave/pulley and apply manual brake to cable drum Close BOPs (optional) Repair or replace power pack Open BOPs, unclamp wire and recommence operations.

Broken Strand Breaking a single strand of a braided cable should be discovered by: •

The winch operator noticing a dark spiral line in the cable caused by the missing strand as the cable is winched in

and/or •

Fluctuations in the line weight, caused by the lower end of the broken strand stripping back off the cable and bunching up inside the lubricator, beneath the grease injection flow tube.

A broken strand is more likely to occur after closing the BOP on the cable and special attention should be paid when operations are recommenced. It can also be caused by crimping the wire, e.g. when using clamps, by excessive bending, etc. Good cable handling and protection procedures and special care during rig up is recommended. In all broken strand/birds nest situations, there is a danger that strands of wire can foul the BOPs causing them not to seal or be damaged when actuated. If correctly functioning BOPs are not available, then the well will have to be killed. Ensure that: • •

The cable is not moved down too much, keeping the broken strand/birds nest to the top of the lubricator The BOPs are closed carefully, checking that there is no unusual resistance.

During recovery from broken strands and birds nests, the lubricator may need to be raised more than normal, and extra tugger lines may be required. On set-ups other than on drilling rigs, this may be difficult to arrange.


53


If this problem is identified early enough, before a birds nest is formed, it may be possible to cut the broken strand back in such a way that it will pass through the flow tube. To attempt this operation: • • • • • •

• • • • • • • •

54

Pump open the head catcher to spread the fingers Attempt to go down a few feet to check if the broken strand is caught. Do not go down too far, as the strand will foul the BOPs Close BOP rams, bleed down lubricator pressure and inflow test BOPs Pump the head catcher open to withdraw the fingers Open the lubricator and clamp the cable above the BOPs Lift up slowly and check that: 1. The wire is not being stripped through the BOPs 2. Cable tension limits are not being exceeded Once it has been established that the cable is being dragged up, lift the lubricator up as far as possible Open the lubricator at a second point below the head catcher Using a second tugger line lower the free middle section of the lubricator back down onto the BOPs, revealing the broken strand at the top Cut the broken strand back without bending it and replace it into the lay of the cable. It may be necessary to file down the OD of the cable slightly to ensure the broken strand is not snagged again when attempting to pass it through the injection head Pull tension on the cable, lower grease injection head, checking that the cable underneath does not slack Equalise pressure and open BOPs POOH and replace cable drum.



1.24.7

Wire Birds Nest If a broken strand of cable has not been detected promptly, it will quickly form a birds nest inside the lubricator. Note that when the gap left by the missing strand becomes visible close to the unit, more than 200 ft of strand may already be missing. In the early stages the birds nest may not be too big, or at least may not have caught on the fingers of the head catcher. In this case handle as for a broken strand. However, most often the birds nest will be stuck inside the lubricator, and the main problem is to gain access to it. The action taken will depend on the wellhead pressure: a)

High WHP

In this situation it is not recommended to strip through the BOPs therefore the cable may have to be cut and knotted twice to bring it through the grease injection head. Proceed as for broken strand case to the point of checking if the wire is stuck. If the birds nest is completely stuck inside the riser, it should be possible to strip a short section of cable (1 - 2 ft) through the BOPs to gain access. To prepare the BOPs for stripping: • • • • •

Close bottom BOP ram tightly Close upper BOP ram lightly and inject grease to a pressure at least 500psi above WHP Apply sufficient pressure on upper BOP rams to just stop the leak of grease Reduce pressure on bottom BOP ram to the same as upper Monitor for grease leaking and adjust upper BOP pressure accordingly.

To recover from the stuck birds nest: • • • • • •

Install first clamp and reconnect the lubricator at the bottom. Open the lubricator at the top one section below the ball valve Cut cable below birds nest and allow the cut end to fall into the lubricator Lay down the lubricator and remove a single section, then lay the grease injection assembly down and remove birds nest Prepare the cut end to pass more easily through the injection head by filing it down Pick up lubricator and pass a rope down from the bottom to be able to pull the cut end back up Thread cut end through injection head.

NOTE:

• • •

That since the injection head is usually shorter than riser sections, removing one will give sufficient slack to allow the cable to be passed through to the top Knot cable, pick up slack, remove clamp and reconnect lubricator Equalise pressure and open BOP rams Pull knot onto drum carefully, using clamp and moving upper sheave up/down to provide slack to pass knot over sheaves.


55


It is good practice to include one more section of riser than required to accommodate the tool, to avoid having to cut the wire twice in this situation. Also, the riser and lubricator together may be able to accommodate the tool, or the DHSV may be used to temporarily close the well to allow the tool to be recovered. If not, the missing lubricator sections will have to be replaced. In this case, it may be expedient at the time of making the first cut to remove all the lubricator sections except one, which will provide enough slack to pass the free end over both sheaves before knotting. To make the second cut: • • • • • •

Pull sufficient cable to move knot securely onto cable drum Close BOP rams and bleed down lubricator pressure Break out lubricator, install clamp and cut cable leaving sufficient length to install original lubricator sections and leave cable end free of lower sheave Re-install lubricator sections, knot cable and remove clamp Re-connect lubricator, pressure test, equalise pressure and open BOP rams Pull out of the well and change out cable.

Low WHP In this situation it may be possible to strip cable through the BOP rams and simplify the operation. After cutting the cable below the birds nest as before: • • •

1.24.8

Knot the free cable ends together without the lubricator and injection head Pull the cable to strip through the BOP. Be ready to close the second BOP if required. Monitor cable tension closely Once enough slack has been pulled, re-clamp the cable, cut off the knot, and thread cable through lubricator and injection head as above.

Tool Stuck Across Tree When retrieving wireline plugs from the tubing hanger it is important to consider the consequences of getting the pulling tool stuck on the plug and the wire breaking without being able to recover the tool string. In the situation where the wireline BOPs and lubricator are rigged up directly on top of the Xmas Tree, the tool string may be straddling both the Xmas Tree valves and the BOPs. In this case there will be no mechanical method of closing the well in order to remove the lubricator, if the plug has been equalised or unseated, and the well is live. The only available option would be to freeze the wellhead in order to provide an ice plug pressure barrier for rigging down the lubricator and rigging up to fish the tool string. To avoid the above mentioned problem either: • •

56

Include a riser section between the tree and the wireline BOPs of sufficient length to accommodate the entire tool string Reduce the length of the tool string so that it will not straddle both the tree valves and the BOPs.



If space constrictions do not allow for any additional height to install a riser section then reducing tool string length is the only option. There are tools available that combine tubular jars, hydraulic jars, weight bars and rope socket in one short section thus providing a tool string short enough to allow the wireline BOPs to be closed above it. 1.24.9

Broken Wire Broken wire has different consequences for slickline and braided line. Slickline has a high stiffness to weight ratio and will not bundle and drop in the tubing. Broken slickline will fall and usually coil in a neat helix on the interior of the tubing, and can be normally easier to fish than braided line. However all fishing operations carry a high element of risk that the fish cannot be recovered. This might lead to killing the well by bullheading, leading to loss of production. In extreme cases it can lead to wells being abandoned. In all cases, fishing operations are to be avoided if another option is available. Broken braided line can form a bundle, which can sometimes be fished with difficulty, but usually which will plug the tubing. This may require the well to be killed (which itself could be difficult with plugged tubing) and the completion retrieved. For this reason braided line should always run with a weak point at the tool, designed to shear out and leave a clean fishing neck before tension limits are exceeded at surface. Greater care is required when dealing with cases of stuck tools with braided line. Slickline tends to part more easily than braided line for a number of reasons, including: • • • • •

Work hardening at pulleys caused by excessive jarring at the same point on the wire Embrittlement of the wire due to the presence of H2S Incorrect make-up of the rope socket Accidental (or otherwise) closing of valve on wire Pulling in excess of the wire’s yield strength.

Particularly with braided line, if the tools are on bottom and the wire parts at surface, there is a good chance that the end of the wire will drop through the stuffing box and BOPs. The ball valve in the stuffing box should stop any escape of hydrocarbons, however the well should be closed in at the tree. Particularly with slickline, if the wire breaks the broken end often is bent enough that it catches on the stuffing box and does not fall in the well. This happens particularly during slickline jarring operations, when the device in the well is stuck. Then a decision has to be made whether to cut the wire on bottom or to fish the end of the wire back out, splice onto it and keep jarring. The latter is not recommended if the line is fatigued as there would be a risk of parting the wire again. However, if the tool string is latched onto the fish with a shear down tool it would be relatively simple to splice onto the line, jar down and release the tools, then come out of the hole and spool on a new line.


57


The most likely location for the wire to have parted downhole is at the rope socket. The well bore pressure will be acting such as to force the line out of the stuffing box, but this will be counteracted by the weight of the line in the well. It is therefore recommended to: • • •

POOH, using increased stuffing box and/or grease injection pressure, to a point where stripping becomes necessary. However be careful not to clamp the cable too tightly, or it will kink Close the rams lightly (one set only) Strip the wire out of the hole.

Caution should be exercised as the end of the line comes through the BOP rams. If the stuffing box/grease injection head does not contain a ball valve then there should be someone ready by the wellhead to close the tree in as the wire passes.

NOTE:

58

That spliced cables are unacceptable for all operations involving pressure control equipment.



CONTENTS

1.


1

1.1

REVIEW OF COILED TUBING OPERATIONS

1

1.2

COILED TUBING PRIMARY SURFACE EQUIPMENT 1.2.1 Reel Unit 1.2.2 Coiled Tubing Operational Life 1.2.3 Tubing Injector Head 1.2.4 Power Systems And Controls 1.2.5 Control Cabin

4 4 6 10 12 12

1.3

COILED TUBING PRIMARY PRESSURE CONTROL EQUIPMENT 1.3.1 Stripper Packer 1.3.2 Annular BOP 1.3.3 Risers And Connectors 1.3.4 Multi-Function Remote Controlled BOP or Quad BOP 1.3.5 Separate Shear/Seal BOP 1.3.6 Combi BOPs 1.3.7 Check Valves 1.3.8 Release Joints

14 14 19 20 20 24 24 27 29

1.4

TYPICAL EQUIPMENT CONFIGURATIONS 1.4.1 Land Based Rig Up 1.4.2 OffShore Platform Rig Up 1.4.3 Sub-Sea Rig Up

31 31 31 31

1.5

EQUIPMENT TEST PROCEDURES 1.5.1 Pre-Load Out Checks 1.5.2 Pre-job Test Procedures

33 33 33

1.6

EMERGENCY PROCEDURES 1.6.1 Production Platform Considerations 1.6.2 Yellow Alert (Production Shutdown) 1.6.3 Red Shutdown (Muster Stations) 1.6.4 Prepare To Abandon

39 39 39 39 39

1.7

SPECIFIC OPERATIONAL AND CONTAINMENT PROBLEMS 1.7.1 Controlling Formation Pressure 1.7.2 Well Circulation For Solids Removal 1.7.3 Fluid Type 1.7.4 Washing With Nitrogen 1.7.5 Washing With Foam 1.7.6 System Frictional Pressure Losses 1.7.7 Fluid Density 1.7.8 Considerations When Unloading A Well

40 40 41 41 42 43 43 44 44


i


ii

1.8

EQUIPMENT FAILURE 1.8.1 Introduction 1.8.2 Run In And Pull Out Of Hole Procedures 1.8.3 Running In Hole Procedure 1.8.4 Stuffing Box/Stripper Failure 1.8.5 Major Riser Assembly Leak 1.8.6 Pinhole At Surface 1.8.7 Tubing Parted At Surface 1.8.8 Tubing Parted Downhole 1.8.9 Internal Coiled Tubing Well Pressure 1.8.10 Loss Of Power 1.8.11 Coiled Tubing Collapse 1.8.12 Coiled Tubing Runaway 1.8.13 Stuck Coiled Tubing 1.8.14 Well Shrinkage

45 45 45 46 47 49 52 55 58 60 60 61 63 64 65

1.9

CASE HISTORIES 1.9.1 Riser And BOP Rig Up 1.9.2 Operational Summary 1.9.3 Conclusions And Recommendations

66 67 67 67



1.


1.1

REVIEW OF COILED TUBING OPERATIONS Coiled tubing is utilised for a variety of operations Figure 1 and Figure 2, including: Workovers Cleanout wellbore debris Acid washing Spotting cement plugs Setting straddle packers/bridge plugs Fishing

Stimulation Removal of wellbore skin damage Spotting diverter agents Clean out un-displaced fracture proppant

Production Services Gas Lifting Small bore permanent strings

Drilling Operations Freeing stuck drill pipe Drilling out flash set cement Cementing Drilling slim hole Side tracking

Logging Operations Stiff wireline (horizontal wells)

Testing Operations Gas lifting Wellbore cleanup


1


Figure 1 - Sand Cleanout with Coiled Tubing

2



Figure 2 - Gas Lift


3


1.2

COILED TUBING PRIMARY SURFACE EQUIPMENT

1.2.1

Reel Unit Coiled tubing is stored on large reels in the same way as electric cable is stored for downhole logging operations. The reel is supported on an axle and is rotated by a drive chain driven by an hydraulic motor. The drive system has a dual function: •

When uncoiling tubing i.e. when running into the well, the motor acts as a constant torque brake, keeping the tubing between the reel and the gooseneck in constant tension. • When coiling tubing, the reel rotates in order to keep the tubing under constant tension. The reel drive system is not used to raise or lower tubing into the well. To ensure that the tubing is correctly coiled onto itself a reeling guide’is synchronised with the rotation of the reel by a chain drive taken from the axle. The inner end of the coiled tubing is connected to the hub of the reel, which incorporates a rotating joint. Fluids can be pumped through this joint and down the coiled tubing while the reel is stationary, or rotating, at any pressure up to the specific working limit of the coiled tubing itself. In order to be able to circulate a ball down the work string, to operate downhole tools, the coiled tubing reel is fitted with a ball launcher. The launcher allows the ball to be introduced into the coiled tubing without the need to depressurise or break any connections. Typically two coiled tubing reels are supplied for each operation in case of a failure of the primary reel. Without tubing

9,000 lbs

With 15,000 ft 11/2” tubing (0.125 wall)

36,000 lbs

Tubing length 11/4” 1

1 /2”

17,000 ft 13,000 ft

Dimensions Length

12 ft

Width

8 ft

Height

10 ft Table 1 - Reel Unit Dimensions

4



Figure 3 - Typical Coiled Tubing Rig Up


5


1.2.2

Coiled Tubing Operational Life As the types of services being performed with coiled tubing increase, the demands on the coiled tubing pipe itself increase. It is important that the limitations of the coiled tubing pipe are thoroughly understood, before these more demanding services are performed. Typical properties are given in Table 2. Since its introduction in the mid 60’s, coiled tubing has developed a somewhat checkered history. There were too many stories about pieces, or entire strings of coiled tubing left in wells. During the 70’s and early 80’s the use of coiled tubing reached a plateau, primarily because of its poor service quality record. In recent years, tremendous improvements have been made in the quality of coiled tubing pipe and in the understanding of coiled tubing limitations. These improvements have resulted in a decrease in coiled tubing pipe failures, and an increased acceptance of coiled tubing applications. There are four coiled tubing limitations that must be understood: 1.

Life Limits

When being run on and off the reel and over the gooseneck. (often with internal pressure on the pipe)

2.

Tension Limits

Which vary with depth and weight of coiled tubing.

3.

Pressure Limits

Burst and collapse pressure vary with tension and compression.

4.

Diameter and Ovality Limits Real time monitoring of the pipe is required to ensure that the pipe is not ballooned, ovaled, or mechanically damaged.

It is important that all these limits are considered together. For example the life limits allow 1.25” OD coiled tubing with a 0.087” wall thickness, made of 70,000 psi yield material, with 5,000 psi internal pressure, to be cycled in and out of the hole about 40 times before reaching the limit. This means that the pipe will not fail due to fatigue before this point. However, when the pipe reaches this limit, it will have grown from 1.25” OD to 1.5” OD, which is far beyond the acceptable diameter limit.

6



OD

Dimensions (ins) wall

ID

Weight lbs/ft

nom

nom

nom

nom

0.875 1.00 1.00 1.00 1.00 1.00 1.00 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.50 1.50 1.50 1.50 1.50 1.50 1.75 1.75 1.75 1.75 2.00 2.00 2.00 2.00 2.375 2.375 2.375

0.087 0.067 0.075 0.087 0.095 0.102 0.109 0.075 0.087 0.095 0.102 0.109 0.125 0.134 0.156 0.095 0.102 0.109 0.125 0.134 0.156 0.109 0.125 0.134 0.156 0.109 0.125 0.134 0.156 0.125 0.134 0.156

0.701 0.866 0.850 0.826 0.810 0.796 0.782 1.100 1.076 1.060 1.046 1.032 1.000 0.982 0.938 1.310 1.296 1.282 1.250 1.232 1.188 1.532 1.500 1.482 1.438 1.782 1.750 1.732 1.688 2.125 2.107 2.063

0.737 0.688 0.741 0.848 0.918 0.978 1.037 0.941 1.081 1.172 1.250 1.328 1.506 1.597 1.840 1.425 1.522 1.619 1.836 1.955 2.245 1.910 2.190 2.313 2.660 2.201 2.503 2.671 3.072 3.010 3.207 3.710

Load capacity yield min lbs 14,455 12,982 14,505 16,738 18,191 19,262 20,492 18,409 21,301 23,194 24,595 26,210 29,375 31,583 35,867 28,197 29,928 31,928 35,862 38,620 44,004 37,645 42,350 45,657 52,140 43,363 48,837 52,694 60,277 58,568 63,250 72,482

Pressure capacity psi Burst Tested yield 10,624 7,056 7,952 9,296 10,192 10,864 11,648 6,362 7,437 8,154 8,691 9,318 10,573 11,469 13,261 6,795 7,243 7,765 8,885 9,557 11,051 6,656 7,552 8,192 9,472 5,824 6,608 7,168 8,288 5,565 6,036 6,979

13,280 8,820 9,940 11,620 12,740 13,580 14,560 7,952 9,296 10,192 10,864 11,648 13,216 14,336 16,576 8,493 9,053 9,707 11,107 11,947 13,813 8,320 9,440 10,240 11,840 7,280 8,260 8,960 10,360 6,956 7,545 8,724

Table 2 - Sizes, Dimensions, Pressure Ratings and General Information about Commercially Available Coiled Tubing. Load capacity - Yield minimum calculated on minimum wall. Tested: Test pressure value - 80% of internal yield pressure rating. Maximum working pressure is a function of tube condition and is determined by user. All data is for new tubing at minimum strength.  RIGTRAIN 2002 – Rev 1

7


In order to more accurately track fatigue loading conditions in the field, most coiled tubing companies have developed computer based systems to quantify and record the historical job exposure of each string. Depending on the internal pressure present in each section of the coiled tubing while reeling, unreeling or travelling over the gooseneck, varying factors are applied to the cycle count to adjust the cycle life of that section. Past and present job data are merged and kept on file to maintain up-to-date records for each string. The calculation and table below serve to demonstrate how coiled tubing is stressed beyond its elastic limit each time it is run over the gooseneck or spool. Yield strength is reduced considerably when stressed with internal pressure. The minimum bend radius for coiled tubing around the reel or gooseneck can be calculated using: R = E (D/2) / Sy

(answer in inches)

E = 30 × 106 psi

(modulus of elasticity for steel)

D = OD of coiled tubing Sy = material yield strength for 70,000 psi coiled tubing: Coiled tubing OD

Minimum bending radius (ft)

0.75

13

1.00

18

1.25

22

1.50

27

1.75

31

2.00

36

2.375

42 Table 3 - The Minimum Bending Radius

Beyond this minimum bending radius the steel will be stressed beyond its elastic strain limit. When coiled tubing is initially spooled plastic deformation will take place. There are six bending and straightening cycles. (Refer to Figure 4)

8



Figure 4 - Bending Cycles 1&6

Pipe is pulled off or spooled on by the injector head. The reel hydraulic motor resists placing the coiled tubing in tension and straightens the primary bend in the coiled tubing.

2&5

Around the gooseneck the coiled tubing is bent around a similar radius to the reel.

3&4

The pipe is straightened again as it passes through the injector and into or out of the well.

Buckling can also be a problem when running coiled tubing. If upward drag forces are greater than downward injector forces then the coiled tubing will be in compression, and helical buckling can occur. A contributory factor is the material microstructure due to the spooling process.


9


1.2.3

Tubing Injector Head The injector head is mounted above the BOPs and stripper and drives the tubing to be run into and out of the well under pressure. The coiled tubing is gripped between contoured blocks which are carried by two sets of double row chains. The chains are driven hydraulically to inject or retract the tubing with precise control. It is important that the correct pressure be maintained on the drive chains to prevent the tubing from being crushed or letting it slip, through insufficient grip. This is achieved by hydraulic tensioning cylinders which act on the chains through a roller system. Two opposed rows of drive blocks are forced inward by a series of hydraulically controlled rollers to provide the friction drive system with the necessary force. This also provides the flexibility necessary to maintain uniform loading on the work string without loss of traction. Units are available with pulling power of up to 60,000 lbs. A high and low gear is available to run the coiled tubing at speeds of 125 and 250 ft/min respectively. The chains and their motor and gearbox drive system are mounted in a sub-frame, one side of which is hinged. The opposite lower side rests on a hydraulic load cell which is connected to a weight indicator in the control unit. The forces exerted by the action of the driving system and the tubing weight are all applied along the centre line of the tubing and cause the frame to pivot. The deflection is small and is controlled by the compressibility of the load cell. The injector head is also equipped with a roller guide, a gooseneck, on the top of the main frame which is used to receive coiled tubing from the reel and guide it into the chain blocks; Figure 5. Weight

10,000 lbs (with gooseneck)

Length

10 ft (including skid)

Width

8 ft

Height

11 ft Table 4 - Injector Dimensions

Injector head weight indicators are the main source of information on downhole coiled tubing performance and as such are the single most important instrument on a coiled tubing unit. Strain gauge instruments are the most accurate type and are becoming more prevalent.

10



Figure 5 - Injector Head


11


1.2.4

Power Systems And Controls All coiled tubing surface power and control systems are hydraulic. A hydraulic pump provides oil for the drive motors of the injector, while a second pump is used to drive the reel. Output regulators are used to control the operation of the injector and reel. In response to the operators demand, the regulators are used to impose a given oil pressure on the hydraulic motors which is converted directly up to a maximum attainable torque. Adjustable relief valves on the injector drive circuit can be set to limit pressure, restricting pull and thrust to within the safe working limits of the coiled tubing. This is particularly important when working with small to medium sized coiled tubing strings, in large casing, where critical buckling loads are only a few thousand pounds. The hydraulic tensioner for the injector chains and the stuffing box control are hydrostatic systems, each with its own hand pump. The BOP is hydraulically controlled by oil stored in an accumulator. The accumulator is charged by a hydraulic pump by means of an activator valve. When the accumulator is fully charged, the blowout preventer can be taken through two complete cycles before recharging is necessary. A hand pump is provided for emergency operation after the accumulator is depleted. The BOP can also be operated manually.

1.2.5

Control Cabin The coiled tubing control cabin is sited to provide a clear view of both the injector head and the coiled tubing reel. It houses all the controls relevant to the operation, including: (Refer to Figure 6) • • • •

12

The main hydraulic control panel (to control the injector reel and spooler system) Well control package (Stuffing box, BOP functions) Recording instrumentation Depth correlation.



Figure 6 - Coiled Tubing Unit Control Panel


13


1.3

COILED TUBING PRIMARY PRESSURE CONTROL EQUIPMENT Pressure control equipment includes: • • • • • •

Stripper sealing devices Annular BOP Riser/flanges/quick unions/hydraulic latches Multifunction remote controlled BOPs Shear seal BOPs Kill lines and valves.

At least two barriers should be available at all stages of an operation to prevent the release of hydrocarbons. All connections between the wellhead and the nearest barrier device capable of forming 100% blind seal should be metal ringed sealed flange. BOP should have the following as a minimum: • • • • • • •

Blind Shear Slip Pipe Flanged connection below the blind rams Equalising valve across the pipe ram Equalising valve across the blind ram.

Hydraulic connectors should only be used above the primary shear and seal BOP. The release mechanism should be designed so that: • • • 1.3.1

It cannot be activated when the connector is exposed to wellhead pressure It remains latched by means of a simple pressure mechanical system An indication device displays the latch status.

Stripper Packer The stripper packer (or stuffing box) is the primary sealing mechanism for isolating wellbore fluids while under static or dynamic operating conditions. A conventional stripper is shown in Figure 7.

14



Figure 7 - Conventional Stripper Conventional Design The conventional stripper packer uses an hydraulic piston operating from below, to compress a polyurethane element to effect a seal around the outside of the coiled tubing. Wear bushings made of brass are run above and below the sealing element to centralise the tubing before entering the packer insert. A Teflon non extrusion ring above the packing element is required to minimise extrusion for maximum packer seal life. For changing out packer inserts and wear bushings with the coiled tubing in situ, a split cap at the top of the stripper packer is removed allowing the consumable parts to be replaced.


15


Side Door Stripper The side door design of a stripper has the following advantages over the conventional design. (Refer to Figure 8) It minimises the distance between the stripper and the injector chains, thus substantially reducing the length of unsupported tubing. It permits replacement of the stripper element, energiser and bushings from the open space below the injector, thus stripper element change out is always easier particularly when tubing is in the well. The side door stripper is more commonly used than the conventional one. Dual Strippers The use of two strippers in one stack of coiled tubing pressure containing equipment is becoming increasingly popular. The lower element is not energised and therefore kept in reserve. Should the upper element become worn, the lower element can be energised and either: • •

16

The operation continued utilising the lower element as the primary seal The upper element can be replaced and the lower element de-energised. (Refer to Figure 9)



Figure 8 - Side Door Stripper


17


Figure 9 - Tandem Side Door Stripper

18



Figure 10 - Radial Stripper 1.3.2

Annular BOP The coiled tubing annular BOP is designed to provide a seal around the outside of the tubing in normal operations. The annular BOP can be used to seal on tool strings of different diameters, collapsed tubing, wireline or to seal blind. Typically run below the quad or combi BOPs, but can also be run below a single stripper/packer, as a backup, instead of having a dual stripper. (Refer to Figure 10) The annular BOP should only be used in addition to a multifunction BOP. Annular BOPs will be described in detail in the snubbing section.


19


1.3.3

Risers And Connectors Risers with quick unions or ring sealed flanged connectors are used on coiled tubing operations. There is a tendency to use the flanged connectors if possible. Some authorities insist upon flanged connectors. In high pressure operations it would be essential. The flanged connector is more reliable than the quick union. However, it takes longer to rig up than the quick union. Depending upon the operation, wellhead pressure, availability, and cost, a judgement would have to be made. The hydraulic connector is used as an interface between pressure control devices. It provides a quick means of rig up. Originally designed for use on floating vessels, the hydraulic connector is becoming standard in all rig ups for some operators and service companies. Hydraulic connectors should be: • • • •

1.3.4

Only used above the primary shear/seal preventer Fail safe Mechanically latched Able to indicate latch status.

Multi-Function Remote Controlled BOP or Quad BOP A quad BOP has four pairs of ram actuators with the following functions, in order, from the top down (Refer to Figure 11)

Blind rams

Used to seal the well bore off at surface when well control is lost. Sealing of the blind rams is achieved when the elastomeric elements in the rams are compressed against each other. For the blind rams to seal correctly the tubing must be removed. The rams are designed to hold pressure from below only.

Shear rams

Used to cut coiled tubing in an emergency. Rams have replaceable blades specifically for coiled tubing applications. As the shearing plates are closed on the coiled tubing, the forces imparted mechanically yield the body of the tube to failure. The cut will leave the tubing open ended so that circulation is still possible.

Slip rams

Designed to hold the tubing and prevent upward or downward movement. Rams have replaceable inserts for changing tubing size. To prevent damage of the tubing, by the slips, longer inserts are available adding 75% to the contact area. In order to break up the stress risers (caused by circumferential slip marks) the teeth have vertical grooves cut to interrupt the slip marks on the tubing.

Pipe rams

The pipe rams are equipped with elastomeric seals sized to the diameter of the tubing in use. When closed on the tubing they isolate the well annulus below the rams. Guide sleeves fitted to the ram assembly centralise the coiled tubing as the rams close.

BOPs are available in 5,000, 10,000 or 15,000 psi ratings. The bore range is 2.5 to 6.4 inch.

20



The blind rams and shear rams are separated from the slip rams and pipe rams by a flanged outlet in the BOP body which is used as a kill line during well control. This line can be used to reverse circulate fluids however it is not recommended as the pipe rams and slip rams would be exposed to debris which could impair their operation. Returns should either be taken via the Xmas Tree or through a flow-tee mounted directly below the BOPs.

Figure 11 - Quad BOP

NOTE:


Some operators prefer not to function slip rams unless absolutely necessary. The extent of slip ram damage cannot be easily quantifiable by visual inspection.

21


The blind ram and pipe ram compartments of the BOP stack body are equipped with ports, which when activated, equalise pressure within the ram body. Since the rams are self-actuating, the pressure above and below must be equalised before they are opened. It is good practice to monitor the opening and closing hydraulic pressure. A high opening pressure could indicate that the riser pressure is not equalised. In this case the surge an opening can cause buckling or other damage. Should a situation arise where the tubing has to be cut, the order of operation should be: • • • •

Close the slip & pipe rams Cut the coiled tubing with the shear rams Using the injector pull the remaining coiled tubing above the blind rams Close the blind rams.

Circulation down the coiled tubing is then possible via the circulating port in the BOP body and into the cut end of the coiled tubing. (Refer to Figure 12) There are six ways of closing the BOP: • • • • • •

22

Hydraulic pressure from the BOP control circuit Accumulator pressure from the BOP control circuit Haskel pump Manual override for Haskel pump Manual hydraulic hand pump Manual handles on the BOP rams.



Figure 12 - Coiled Tubing Cut


23


1.3.5

Separate Shear/Seal BOP This item sometimes referred to as the safety head is rigged up directly on to the Xmas Tree. It should always be considered especially when a live well situation could be induced as it protects the riser. It is essential for emergency shutdown situations. (Refer Figure 13 and Figure 14)

1.3.6

Combi BOPs The combi BOP has the same features as the quad BOP but combines the functions of two rams in one actuator: (Refer to Figure 15 and Figure 16) • •

Quad BOP blind and shear rams become combination shear/seal rams Quad BOP slip and pipe rams become combination pipe/slip rams (see slip rams).

Consequently with combi rams a quad BOP becomes a dual BOP. This reduces height, weight and the number of hydraulic hoses required. The advantages of the combi BOP over the quad BOP is that the coiled tubing does not need to be pulled out above the blind rams in order to affect a seal, thus enabling the well to be secured more rapidly in a emergency situation. All rams are operated hydraulically via a 10 gallon accumulator bottle with a 3,000 psi operating pressure. The bottle is automatically recharged when the pressure falls to 2,700 psi. The 10 gallon bottle provides enough usable fluid to close all the BOP functions should the power pack not be running.

24



Figure 13 - EH44 Single BOP

Figure 14 - Shear Seal Actuator Assembly


25


Figure 15 - Wellhead Combination BOP

Figure 16 - Combi BOP Ram Assemblies

26



1.3.7

Check Valves When using coiled tubing on a live well it is standard practise to incorporate a check valve (non-return valve) in the bottom hole assembly. Its function is to guard against a blow out if the tubing leaks or parts at surface by preventing flow back up the string. There are four types of check valve commonly available. (Refer to Figure 17) • • • •

Ball Dome Dart Flapper.

The flapper valve is designed for use in conjunction with ball operated tools because the dart valve will not allow the passage of a ball. Should a bottom hole assembly become stuck a ball can be pumped through the flapper to operate the shear sub, while still providing check valve protection for the coiled tubing as it is retrieved from the well. Hence the flapper valve is in more common use and typically two valves are run in tandem or a dual flapper valve is used to give backup in case of one flapper failing to seal.


27


Figure 17 - Coiled Tubing Check Valves

28



1.3.8

Release Joints Although not strictly an item of primary pressure control equipment, the release joint provides a means of disengaging the coiled tubing from the BHA, in case it is unexpectedly stuck down hole. Because of its larger size the BHA has a tendency to hang up on down hole obstruction especially on a highly deviated wells. There are three basic types of Release Joints: • • •

Ball operated shear sub (BOSS tool) Hydraulic disconnect Tension disconnect.

Ball Operated Shear Sub The BOSS tool is activated by circulating a ball through the coiled tubing into a seat at the top of the tool. A pre-determined pressure applied through the coiled tubing shears out a lock pin and moves an internal sleeve down to release the retaining lugs. This allows the two halves on the tool to separate leaving a standard internal fishing neck looking up. The ball is introduced into the flow path through a ball launcher, which is fitted to the coiled tubing reel unit. Boss tool operation can be seen in Figure 18. Hydraulic Disconnect The hydraulic disconnect is similar in design to the BOSS tool, but does not rely on a ball for activation. The tool is operated by applying a differential pressure inside the coiled tubing. It requires a much larger differential pressure because the surface area on which it is acting is much smaller. Tension Disconnect These are simply two components pinned together such that they will separate upon application of a straight pull on the coiled tubing, leaving a standard fishing neck looking up. It is not generally recommended to use the tension disconnect as part of the down hole tools because of the lack of control over down hole tension forces and the possibility of premature release.


29


Figure 18 - Boss Tool Operation

30



1.4

TYPICAL EQUIPMENT CONFIGURATIONS

1.4.1

Land Based Rig Up Typically for land based coiled tubing operations the BOPs can be rigged up directly onto the Xmas Tree with no need for a riser. However if the toolstring configuration is complex and hence long in length a riser can be installed below the BOPs.

1.4.2

OffShore Platform Rig Up Figure 3 shows a typical rig up for an offshore platform where the injector head and BOPs are positioned on a higher deck (probably the drill floor) than the wellhead. A riser connects the BOPs and the Xmas Tree which acts as a lubricator for long toolstrings. In order to be able to secure the well in an emergency and have the ability to depressurise the riser a shear/seal BOP is usually included in the rig up, directly above the Xmas Tree.

1.4.3

Sub-sea Rig Up Sub-sea coiled tubing operations from a floating rig require the injector head and BOPs etc. to be compensated to allow for rig movement. The injector head, BOPs and stripper are housed in a lift frame which is suspended from the drilling blocks. The riser and sub-sea BOPs are in turn suspended from beneath the lift frame, commonly through a hydraulic connector for ease of rig up, and are kept in constant tension when attached to the sub-sea Xmas Tree to avoid buckling of the riser joints. The sub-sea completion BOP will have the same functions as the shear/seal BOP run above the tree on a platform rig up. A hydraulic control umbilical is run back to surface to allow remote operation of the tree valves, SCSSV and BOP functions. There will be an emergency disconnect sub above the BOP to allow the riser to be released and the rig moved off location, in the event of a problem, leaving the well secured with the BOPs. (Refer to Figure 19)


31


Figure 19 - Movement Compensated Coiled Tubing Assembly

32



1.5

EQUIPMENT TEST PROCEDURES

1.5.1

Pre-Load Out Checks In addition to the pre-job offshore testing the following measures could be taken prior to the equipment leaving the base. The coiled tubing unit should be run and full function checks performed. With straight bar inserted apply a pressure test to the stuffing box to check the operation. Record on a chart. Pressure test all coiled tubing reels that are going on the job with water to a high and low pressure. Record on a chart. A depth flag (paint mark or ring) positioned +/- 300 ft from the end of the coiled tubing for counter verification when pulling out of hole. Coiled tubing pickled in HCl to remove any corrosion/debris deposits and then neutralised and tested to maximum rated pressure. Displace a ball of suitable diameter through coiled tubing reel(s) with N2. Leave tubing purged with N2 at atmospheric pressure. Test cut a section of coiled tubing with pipe and slip rams closed. Inspect cut for deformation and inspect all ram contact areas. Replace shear cutters. (If stiff wireline operations are to be undertaken, test shear coiled tubing and cable together). Replace shear cutters. BOP body test to maximum rated pressure and to 200-300 psi low pressure. Record on a chart.

1.5.2

Pre-job Test Procedures 1.

Shear/Seal BOP Fill up the riser and BOP via the test line to the tree valve. Close the blind rams. Increase pressure in 500 psi increments to maximum and hold for the prescribed time. Record on a chart. (Refer to Figure 20)

2.

Blind Rams and Riser This should be tested once the BOP is rigged up on the tree and after function testing all rams. Close the lower master valve, fill the tree through the open swab valve. Close the blind ram and test from below via the wing valve on the tree using the cement pump and seawater or water/glycol. Increase the test pressure in 500 psi increments to maximum and hold stabilised pressure for the prescribed time. Record on a chart. (Refer to Figure 21(3)).

3.

Stripper Position the straight bar across the BOP. Fill up via the reel until water overflows from the stripper. Stop the pump, close the swab valve and energise the stripper packer. Increase pressure in 500 psi increments to 5,000 psi and hold for 15 minutes. (Refer to Figure 21(4))

NOTE:


Applying too much stripper pressure may damage the coiled tubing.

33


Figure 20 - Pre-job Test Procedures

34



Figure 21 - Pre-job Test Procedures (Continued)  RIGTRAIN 2002 – Rev 1

35


4.

Coiled Tubing Reel and Running Tools Fill the coiled tubing reel with test water from the cement unit. Displace at least twice the tubing volume to prevent any possible plugging of the coiled tubing small diameter tools by contaminants from any previous work done with the cement unit. During this circulation a chevron pig and stainless steel ball can be used to clear the tubing and establish the reel volume whilst filling up the reel. Suspend the injector by the travelling block and attach the coiled tubing tools; tubing connector, straight bar connections, check valves, shear sub, test cap and valve. Close the test cap and pressure up in 500 psi increments. Hold stabilised pressure for the prescribed time. Record on a chart. Bleed off both ends. Remove the test cap and attach the tools for the impending job.

NOTE: 5.

The end of the string should be as close to deck as possible.

Pipe Rams With pressure still maintained from the stripper test close the pipe rams. Bleed the pressure from above via the BOP circulating port. Observe the pressure which is now being applied to the underside of the pipe rams for the prescribed time. Equalise the pressure above the rams via the equalising valve on the BOP. Open the pipe rams. (Refer to Figure 22(5)).

6.

Check Valves Attach the valves to the coiled tubing in the reverse direction including a bleed off manifold. Position as close to deck as possible. Pressure up in 500 psi increments. Hold for the prescribed time. Bleed pressure off at both ends of the reel. Reinstate the check valves in the string the correct way round. (Refer to Figure 22(6)). Alternatively, after the pipe ram test, bleed off the coiled tubing pressure to 1,000 psi and monitor the check valves are holding the pressure still inside the BOP body. This is assuming the string is good for a differential equal to at least the test pressure being used.

36



7.

To Reinstate The System Equalise the pressure in the coiled tubing. Bleed down the pressure from the BOP and riser to equal the well pressure. Ensure all BOP rams are open. Reduce stripper packer to required level. It will be necessary to free the coiled tubing from the high force applied by the stripper during testing. Do this in the upward direction with the injector chains.

NOTE:


Ensure that when running coiled tubing into a riser, and the well is closed in, that a vent is open to prevent pressure build up which could result in pipe collapse.

37


Figure 22 - Pre-job Test Procedures (Continued)

38



1.6

EMERGENCY PROCEDURES

1.6.1

Production Platform Considerations Specific procedures will vary depending upon the installation but the following are useful guidelines.

1.6.2

Yellow Alert (Production Shut down) 1.

If pumping is in progress, stop and shut down the pumping unit and close valve to isolate flow line.

2.

If a washing or milling operation is in progress the tubing should be lifted above the worked interval and at least above any perforations (to prevent differential sticking if well is taking fluid) prior to shutting down the coiled tubing unit and to prevent solids settling in the annulus. If time permits pull up the equivalent distance from the BOP to the DHSV. If the situation deteriorates (e.g. prepare to abandon) then the coiled tubing can be sheared and dropped so as it falls to below the DHSV which can then be closed.

1.6.3

3.

If the coiled tubing end is above the DHSV, the valve should be closed. A decision to remove this valve from any ESD circuit should have been taken. If the coiled tubing is below the DHSV close the pipe rams and apply the injector brake on the quad and lock them. Close the wing valve.

4.

Shut down the coiled tubing unit, hand back permits.

Red Shutdown (Muster Stations) As per yellow shut down steps 1 to 3 but essential personnel to stay with unit.

1.6.4

Prepare To Abandon 1, 2 and 3 as per yellow shut down. 4.

If the well is live and a separate shear/seal head is rigged up it can be activated. When this is done if the coiled tubing was far enough off bottom the Xmas Tree valves can then be closed.

5.

If the well is live and no shear/seal rams are available, the pipe can be sheared using the quad after the slips are closed. The coiled tubing can then be dropped below the tree and the tree valves closed. The DHSV can also be closed if possible.

If a situation arises where the coiled tubing cannot be pulled off bottom and the well is live the only way to shut the well in is by using the blind rams after shearing the tubing. The remaining coiled tubing must be pulled above the blind rams. If the well is not live, pull the remainder of the coiled tubing out of the BOP and close the blind rams. Close the Xmas Tree valves and DHSV. Shut down the coiled tubing unit.


39


1.7

SPECIFIC OPERATIONAL AND CONTAINMENT PROBLEMS

1.7.1

Controlling Formation Pressure Killing a well during coiled tubing operations would normally be done by bullheading. For example, if coiled tubing collapse occurs. The well can be bullheaded down the coiled tubing, the annulus or both, depending upon the circumstances. However, there are occasions when a well will need to be killed by a circulation method. For example, if coiled tubing is actually being used to perform a kill operation prior to a rig workover. A specific rig up to take returns via a choke will be required. The responsibility for the kill operation being with the operator.

Figure 23 - Coiled Tubing Circulating Rig Up With Option To Rig Choke

40



Figure 24 - Internal Pressure Drop Curves 1.7.2

Well Circulation For Solids Removal Mostly this type of operation is performed to establish communication with an open completion interval. It is therefore important to balance the fluid pressure used to that of reservoir pressure to avoid fluid loss or formation damage. There are a number of factors to be considered: • •

1.7.3

Fluid type - to control solids carrying ability Fluid density - to control hydrostatic pressure.

Fluid Type The compatibility of well fluids and treatment fluids on the well control equipment should be considered: • • •

H2S or CO2 Elastomer seal behaviour Metal reaction.

There are two types of fluid; compressible and incompressible. Incompressible fluids can be subdivided into Newtonian and Non-Newtonian.


41


Properties of Newtonian and Non-Newtonian fluids Viscosity Newtonian e.g. water, brine Non-Newtonian e.g. mud, gels

Low

Turbulent flow

Solids carrying

Annulus

AV must be greater than TPSV Poor

High

Coiled Tubing

Good

Wash fluids must be capable of transporting solids out of the well. Lack of hole cleaning can lead to getting stuck and being unable to circulate, thereby compromising our primary means of well control. If circulation rates will achieve annular velocities exceeding terminal particle settling velocity (TPSV), Newtonian fluids are generally adequate. It is important to bear in mind the different annular capacities when the coiled tubing is washing inside the production tubing or below the tailpipe. It is common practise to use brine or water and to circulate non-Newtonian viscous pills periodically to assist in solids removal. With a Newtonian fluid solids will settle out when circulation is below the TPSV, therefore a gel wash fluid may be considered more desirable. Hole deviation has a great affect on solids removal. With wells of 45 degrees deviation the annular velocity should be twice the TPSV. In horizontal wells the ratio should be at least 10:1. TPSV calculations are possible for Newtonian and non-Newtonian fluids, the latter being more complex. Computer programmes are made available by service companies at the planning stage of coiled tubing operations. Compressible fluids are more difficult to design and use than incompressible fluids. They can be used on wells with low reservoir pressures or to lift solids when annular velocities will be too low with liquid fluids. Compressible fluids consist of a single gaseous phase or a liquid and gaseous phase (nitrogen) as foams. In the annulus the gas fraction of the foam will expand as it is circulated out of the well. This assists with solids removal but does create higher annular pressure losses as compared with liquids. 1.7.4

Washing With Nitrogen In low reservoir pressure wells nitrogen can be used as a wash medium. The solids removal is entirely dependant on the annular velocity. Stopping pumping will immediately cause solids settling. Erosion of coiled tubing and surface production equipment is also a concern.

42



1.7.5

Washing With Foam Foam is formed by commingling a liquid phase (treated with surfactants) with nitrogen gas to create a homogeneous emulsified fluid. Foam can be generated in densities equivalent to 0.35 to 0.057 psi/ft depending on wellbore pressures and temperatures. Foam can most closely be compared to a non-Newtonian fluid. The volumetric gas quantity in a foam is known as quality: Qf = N2 Volume / Liquid Volume + N2 Volume x 100% Foams of quality 60 to 85 percent possess some useful properties. • •

1.7.6

Solids suspension is up to 10 times greater than incompressible fluids The foam can withstand up to 1,000 psi pressure with minimal fluid loss to the formation.

System Frictional Pressure Losses The capability of coiled tubing to withstand theoretical maximum internal pressure (based on API BULLETIN 5C3) is still a topic of discussion because the effects of plastic deformation, caused by the surface equipment, is not fully understood. A maximum circulating pressure should be decided upon prior to any job being planned, after discussion with the service company. As an example one operator chose the following parameters when performing an under-reaming operation with 13/4” coiled tubing, 1.91 lbs/ft, 0.109” wall thickness (WT). Published properties

Operating parameters

Tensile strength

39,300 lbs

32,000 lbs

Burst

10,380 psi

3,800 psi

Collapse

7,260 psi

2,500 psi

Friction pressure losses in coiled tubing and coiled tubing/tubing annulus can be predicted using computer programmes. Annular pressure losses are of the order 10 psi/1,000 ft whereas internal pressure losses are of the order 100 psi/1,000 ft. These figures are quoted to demonstrate the difference in order of magnitude; exact figures would vary depending on individual cases. Formation fluid can influence a wash programme. If the system becomes underbalanced and the formation flows, this can help the removal of solids. If a gas well is being worked on, under balance will lead to a gas influx. Whilst this could also assist with solids removal it is advisable to be prepared for an increase in return flow rate. Additionally, as the gas expands, it will displace the wash fluid either at surface or into the reservoir. A large influx of gas into the annulus will reduce the solids carrying capability. An influx of oil may degrade the foam and cause the same problem.


43


1.7.7

Fluid Density In a well planned operation the hydrostatic pressure of the wash fluid plus the annular pressure loss (APL) should balance the reservoir pressure. As a general guide:

1.7.8

Reservoir Pressure

Wash Fluid

0.100 - 0.400 psi/ft

Foam

0.434 - 0.465 psi/ft

Brine

> 0.465 psi/ft

Heavier brine or weighted fluid

Considerations When Unloading A Well This technique is used to initialise flow during a DST, recommence flow after a workover or when a well has killed itself due to overbalance from produced fluids after a shutdown. As with any unloading technique it is important, particularly in unconsolidated formations, not to shock the formation by unloading too quickly and causing perforation tunnel collapse. On normally and abnormally pressured wells (> = 0.465 psi/ft) an under balance condition can be achieved by running in with coiled tubing to a predetermined depth and displacing a height of fluid to provide the required draw down, whilst maintaining constant BHP by means of an adjustable choke. The coiled tubing is then pulled out of the well and an equivalent volume of formation fluid is drawn into the wellbore. On wells that are sub-normally pressured, and are unable to support a full column of fluid, nitrogen can be used. The most effective method of nitrogen lifting is to run into the well to the fluid level and commence circulating nitrogen while slowly running in hole. This allows for a gradual reduction in the wellbore fluid density causing a controlled flow from the formation. There are some complex considerations when unloading with nitrogen due to the high annulus frictional pressure losses that can be induced in certain coiled tubing/tubing configurations. Basically the smaller the annulus cross sectional area the higher the pressure loss, which can cause cessation of flow when the coiled tubing is pushed below a certain depth.

44



1.8

EQUIPMENT FAILURE

1.8.1

Introduction Coiled tubing is most likely to fail due to buckling when it encounters an object or catches on a change in ID. It is therefore important that the coiled tubing unit operator has a copy of the completion schematic with all IDs clearly indicated and possible hang up points discussed with the company representative.

1.8.2

Run In And Pull Out Of Hole Procedures Potentially most coiled tubing operational failures can occur when running coiled tubing in the hole. The most likely form of failure is due to buckling when the tubing hits some object or catches on a change of diameter. The potential for buckling is a function of the coiled tubing wall thickness, diameter, and the size of the tubing or casing that the coiled tubing is being run into. A full analysis is necessary to determine the minimum weight indicator reading allowable whilst running in the hole. Running Speeds •

•

• • •

The maximum running speed in hole for normal operation will be 50 feet per minute (15 m/min). This may be increased for reasons such as PLTs only if the hole section has been previously traversed to ensure that no restrictions are evident. The maximum running speed is to be reduced to 10 feet per minute (3 m/min), when running through restrictions such as sliding side doors, nipples and gas lift mandrels amongst others. This reduced running speed will be applied for 50 feet (15 m), before and 50 feet (15 m), after the position of the downhole obstruction to allow for any discrepancies in the depth readings. Pulling out of hole speed is not as critical, but will be limited to a maximum of 100 feet per minute (30 m/min). The same speed reductions are to be applied when pulling through restrictions. Pulling out of hole speed will be reduced to 10 feet per minute (3 m/min), when within 100 feet (30 m), of the wellhead or BOP, until the end connector contacts the stuffing box. At all times when running in or pulling out of the hole the injector thrust must be set at the minimum required to move the tubing.


45


1.8.3

Running In Hole Procedure Prior to running in the hole, the coiled tubing supervisor will have the following information available: • • • • • •

Well bore profile or completion diagram Deviation profile of well bore Operating limit predictions The maximum allowable pressure rating of the tubing and the maximum allowable pull Fishing diagram of bottom hole assembly Details of any wireline drift run prior to coiled tubing operations.

Ensure all wellhead and BOP valves are open via a physical check and commence running in hole limiting running speeds as outlined above. Perform pull tests every 1,000 feet (300 metres) or less if circumstances require to ensure that the pick up weight does not exceed the operating limit. These pull tests should not be done at exactly 1,000 feet increments, but should be varied so as to prevent fatiguing the coiled tubing at the same point each time a pull test is performed. Special Precautions Control of remote actuated well valves, while coiled tubing is in a well, must be removed from the automatic shutdown system. Wellhead valves may either be locked open with fuseable discs or control transferred to a separate control skid. Sub surface safety valves may be removed and sleeved, sleeved only, or control transferred to a separate control skid. They should not be held open by locking in hydraulic control pressure at the wellhead as pressure can bleed off over time and allow the valve to close. The wellbore fluid and geometry must always be considered before any coiled tubing operation. The size of the bottom hole assembly in relation to the completion diameter can have a significant effect on the running in and pulling out weight. In the case of large bottom hole assemblies in relatively small tubulars, the annular clearance can be such that significant pistoning effects can occur which resist the movement of the coiled tubing and can cause swabbing of the well. High viscosity fluids in the annulus can also cause this effect. High wellhead pressures cause a significant up thrust on coiled tubing, dependent on the cross sectional area of the tubing. This means that in high pressure wells the weight indicator will read negative until sufficient weight of coiled tubing is in the well to overcome the effect of pressure. In these situations the injector head requires a large amount of hydraulic thrust to ‘snub’ the tubing in the well. The thrust required from the injector reduces as more tubing is in the well and it is important to reduce the thrust setting on the injector as the tubing is run in the well. This means that in the event of the tubing hitting an unexpected object (such as hydrate plug), only a minimal amount of extra thrust will be applied by the injector, reducing the possibility of buckling the tubing. If at all possible circulate through coiled tubing while run in hole.

46



Should buckling occur while running in hole the pipe will form a hinge that will in effect prevent circulation. If pumping liquid this will be noticed by a rapid increase in circulating pressure. In many instances of buckling failure the tubing has been folded over repeatedly before the injector has been stopped, resulting in a difficult fishing operation. Stripper rubbers have a significant effect on apparent coiled tubing weight and low friction strippers must be used at all times. Correct lubricating oil should be used as required to reduce stripper friction further in high pressure dry conditions.

NOTE: 1.8.4

Never use diesel.

Stuffing Box/Stripper Failure The operational life of the stuffing box packings are very dependant on the type of operation being undertaken. Incorrect stuffing box hydraulic pressure, high wellhead pressures, poor external surface of the tubing, and corrosive well bore fluids will accelerate the wear process which may result in the stripper elements failing. (Refer to Figure 25) In the event of stuffing box failure during coiled tubing operations: •

Increase hydraulic pressure to stuffing box in an attempt to stop leak. Normally operating at 200 psi with large operating margin up to 2,500 psi.

If this proves unsuccessful then: • • • • • • • •

Stop both pipe movement and circulation Engage injector brake, close pipe rams Bleed off pressure above pipe rams Close lower stripper (if used) Open (upper) stripper and replace sealing elements. Re-test stripper Equalise pressure and open pipe rams Release injector brake Re-commence operations.


47


Figure 25 - Stripper Failure

48



1.8.5

Major Riser Assembly Leak In the event of a major riser assembly leak developing between the Xmas Tree and coiled tubing BOPs, that cannot be repaired during the coiled tubing operation, the following procedures should be followed: (Refer to Figure 26 and Figure 27) If the leak occurs with a short string of coiled tubing in the hole: 1. 2. 3. 4. 5.

Pull out of hole to above the Xmas Tree (and shear/seal BOP if used). Close the swab valve on the Xmas Tree. Close hydraulic or manual master valve on the Xmas Tree. Bleed off pressure in riser and repair leak. Pressure test all broken connections and re-commence operations.

If the leak occurs with a long string of coiled tubing in the hole: 1. Pull sufficient coiled tubing out of hole to ensure that the string will drop below the Xmas Tree master valve when the shear rams (or shear/seal BOPs) are activated. 2. Close shear rams (or shear/seal BOPs) to cut coiled tubing. 3. Close Xmas Tree swab and master valves. 4. Repair leak in riser and pressure test all broken connections. 5. Commence fishing operations.

NOTE:


If it is not possible to establish two mechanical barriers below the leak normally the well will have to be killed before any repairs are commenced.

49


Figure 26 - Riser Assembly Leak With Long String Of Coiled Tubing In Hole

50



Figure 27 - Riser Assembly Leak With Short String Of Coiled Tubing In Hole


51


1.8.6

Pinhole At Surface If a pinhole leak is observed at surface, coiled tubing operations should be suspended. (Refer to Figure 28 and Figure 29) If bottom hole assembly contains check valves: • • • •

Monitor coiled tubing pressure and observe leak to ensure check valves are holding Pull out of hole to position the leak on the lower part of the reel (be prepared to deal with containment of any hazardous fluid) Displace coiled tubing to leak with water if hazardous fluid being used if this is considered a safer option Pull out of hole and replace coiled tubing reel.

If valves are not holding or have not been included in bottom hole assembly: •

Observe severity of leak and decide whether it is safe to pull out of hole. Factors such as fluid type and area of dispersion will influence decision.

If leak is too severe to continue pulling out of hole: • • • •

52

Close slip and pipe rams Operate shear rams to cut pipe Circulate well to kill fluid through coiled tubing left in well Retrieve remainder of coiled tubing.



Figure 28 - Pinhole Leak (1)


53


Figure 29 - Pinhole Leak (2)

54



1.8.7

Tubing Parted At Surface In the event that the coiled tubing parts at surface: (Refer to Figure 30 and Figure 31) • • •

Attempt to spool as much coiled tubing back on to the reel to avoid whiplash. Equally important attempt to run excess coiled tubing through the gooseneck Stop injector, close slip and pipe rams If personnel are in danger from fluid release and/or the check valves are not holding, operate the shear/seal rams and commence well kill operations.

Otherwise: • • • • •

Monitor WHP while contingency plans are reviewed Kill well and make necessary repairs to coiled tubing Remove injector and feed coiled tubing back through injector chains Install fishing spear. (Depending on the tubing stick-up, other methods of attachment may be more appropriate) Rig up injector and stab into top of fish, pull test spear then release slips and pull out of hole.


55


Figure 30 - Tubing Parted at Surface Check Valves Holding

56



Figure 31 - Tubing Parted At Surface Check Valves Not Holding


57


1.8.8

Tubing Parted Downhole Breakage of the coiled tubing downhole will be indicated by a sudden reduction in weight and circulating pressure. Thereafter: (Refer to Figure 32) • • •

• •

Continue to maintain circulation with water at all times to prevent migration of well fluids up the string. Circulation rate to be kept to a minimum Determine approximate length of coiled tubing remaining from pick-up and hanging weights Pull out of the hole slowly until close to surface then begin to cycle tree swab valve (if possible) every X ft, (where X is less than, or equal to, the riser length), to determine when the end of the coiled tubing has cleared the xmas tree when end of coiled tubing is clear of tree stop pulling out of the hole and close tree swab and master valves Depressurise riser and continue pulling out of hole Commence fishing operations.

The leak should appear as a sudden change in pressure which depends on the circumstances, e.g. if jetting or pumping the coiled tubing pressure will be greater than well pressure and a leak will appear as a sudden reduction in pump pressure (and an increase in injection rate).

58



Figure 32 - Tubing Parted Down Hole


59


1.8.9

Internal Coiled Tubing Well Pressure During most operations well pressure will be prevented from entering the coiled tubing by the dual check valves. If these fail, the tubing itself becomes perforated, or the BHA is lost, well fluids will be able to enter the coil. In this situation it will not be possible to depressurise the coil until the point of leakage is out of the well. If coiled tubing pressure is greater than well pressure i.e. if jetting or pumping, then the leak may appear as a sudden reduction in pump pressure. In the event of well pressure being present inside the coiled tubing: • • •

Stop pipe movement Stop circulating for long enough for the pressure to stabilise and perform a hydrostatic calculation to identify the point of leakage Displace the reel to water and continue circulating at a low rate to stop migration of well fluids up the coiled tubing.

It will be difficult to calculate the exact location of the leak and its severity and hence in most cases it would be advisable to kill the well before attempting to pull out. However if the wellhead pressure is low it may be possible to take the following action: •

•

1.8.10

Continue pulling out of hole while circulating and observe the injector head for signs of leakage passing the stuffing box. If the fluid escaping is the fluid being pumped it may be possible to continue pulling out, after cutting back the circulating rate to a minimum to reduce the risk of a washout parting the pipe If the leak is too severe then run back into the well, set the slips, close the pipe rams, shear the pipe and close the blind rams.

Loss Of Power In the event of a power pack failure: • • • • • • • •

60

Engage injector brake Close pipe rams and manually lock Close manual stems on pipe and slip rams as back-up Apply the reel brake if it is not fail-safe applied While maintaining circulation (if possible), repair or replace power pack Equalise pressure across pipe rams and open pipe and slip rams Release injector brake Re-commence coiled tubing operations.



1.8.11

Coiled Tubing Collapse Coiled tubing can collapse when exposed to higher than design differential pressures. If collapse occurs, it should be evident from a rapid rise in circulating pressure, or becoming stuck when trying to pull the collapsed section of tubing through the stuffing box. Should the pipe become stuck downhole stretch measurements should be made to determine the stuck point. (Refer to Figure 33) With a 5,000 lbs over pull, the stretch for each 1,000 ft of coiled tubing is; 11/4”

6”/1,000 ft

11/2”

5”/1,000 ft

NOTE:

In this situation, stripping the coiled tubing through the pipe rams is not an option because if the collapsed section of tubing straddles the BOPs then they will not be able to seal.

Once it has been established that the coiled tubing is stuck in the stuffing box: • • • • • •

• •

Hang off coiled tubing in slips Kill the well Install clamps on the coiled tubing Split the stuffing box and open the slips Attempt to pull the coiled tubing with the injector head If the injector head is unable to pull the tubing, break the connection above the BOP and raise the injector. Connect to block and pull tubing out of hole to remove collapsed section leaving 4-6 ft of good coiled tubing sticking up for the BOP Set slips Re-connect the injector head, splice the coiled tubing, and pull out of hole.


61


Figure 33 - Coiled Tubing Collapse

62



1.8.12

Coiled Tubing Runaway In both of the following cases the action to be taken will depend on the severity of the situation. The quickest method, but not necessarily the most satisfactory, would be to close the shear/seal rams. Coiled tubing running into well: This is most likely to occur on low THP gas wells where snubbing forces are lowest and string weight greatest. Runaway tubing can occur because of a lack of grip between the drive chains and pipe, caused by under gauge tubing or loss of hydraulic pressure. Once runaway has started it may be difficult to stop, however the following actions can be taken: • • • •

Stop injector head movement and apply more inside tension Increase stripper pressure to a maximum in an attempt to slow down rate of runaway As a last option close the slip rams. This will probably lead to pipe breakage but is the safest option left Under certain circumstances if the runaway tubing is at a speed above the critical speed, the back-pressure created by the circulating hydraulic fluid may prevent the injector motor brakes from actuating. If this situation occurs, select the pull mode for the injector and increase system hydraulic pressure until the tubing comes to a standstill.

Coiled tubing is ejected out of the well: This condition is most likely to occur near surface on high THP wells where snubbing forces are highest. In this situation: • •

Increase stuffing box pressure to a maximum Close slip rams (only effective if slips are double acting).

NOTE:


If the tubing is ejected from the well the blind rams must be closed and injector stopped before coiled tubing passes through the injector chains.

63


1.8.13

Stuck Coiled Tubing When a pull of more than 80% of the yield strength is required to pull the coiled tubing out of the hole, the pipe is defined as being stuck. Before any more pull force is applied, it is essential to analyse the problem and take the necessary precautions. Coiled tubing can get stuck in the following situations: • • • •

Solids settling and packing off around pipe caused by pump failure in cleanout operations Unexpected increase in friction drag Obstruction in well Differential sticking.

How to react in the event of getting stuck: •

• • • •

Try to work the coiled tubing free without exceeding 80% of the yield strength of the pipe. Be aware of the fact that moving the pipe up and down over the gooseneck rapidly weakens the pipe. Pumping while working the pipe should be avoided if possible as this greatly accelerates the fatigue problem. (Check fatigue cycle log to assess if further cycling is possible). Maintain circulation when not cycling If stuck due to drag, circulate a pill of slick fluid to reduce the friction between the pipe and tubing/casing wall Rapidly bleed off annulus pressure (if possible) while pulling on the pipe. This may cause sufficient backflow to dislodge debris Try to increase the buoyancy by pumping heavier fluid into the annulus and displacing the coiled tubing to nitrogen. Be aware of the risk of collapse. Release the BHA by using ball operated shear sub if circulation is possible.

If it does not prove possible to get free using any of the above methods then: • • • • • •

Determine the stuck point by pull tests Hang off the coiled tubing in the slip rams Kill the well Cut the coiled tubing at surface Run chemical cutter* and cut pipe above free point Fish for remainder of coiled tubing as necessary.

* Chemical cutters are run on electric line and can be used to cut tubing down to 1” OD (cutters are available down to an OD of 0.688”). The cut is flare free, burr free, and undistorted and hence provides a good profile for fishing. When making the cut the coiled tubing pressure should be slightly overbalanced to avoid the cutter being blown up the well.

64



1.8.14

Well Shrinkage It is likely that as workover fluids are introduced into a well that has been on production that some shrinkage will occur due to the cooling effect of the workover fluid. This can put the surface support frame into unacceptable compression. Frames have buckled in the past due to this. Allowance has to be made for this possibility. Support frames are available with hydraulic feet that can be adjusted if shrinkage occurs. (Refer to Figure 34)

Figure 34 - Well Shrinkage


65


1.9

CASE HISTORIES A north sea gas injection well was being worked over with a coiled tubing unit when a small, uncontrolled gas leak to atmosphere occurred. The gas leak was brought under control by activating the BOPs, however, attempts to kill the well from the top were unsuccessful and because of a complex tubing fish, the well was both time consuming and costly to secure.

Figure 35 - Case History Coiled Tubing Rig Up

66



1.9.1

Riser And BOP Rig Up The primary barrier was the quad (upper) BOP and the secondary barrier was the shear/seal (lower) BOP with independent control systems. (Refer to Figure 35)

1.9.2

Operational Summary A tubing end locator on 1.25” coiled tubing was being run into the well, to determine the depth of a cement plug, while seawater was being pumped at a rate of 6 l/min. At an odometer depth of 290 m the injector head stalled. The operator, assuming that he was actually at 290 m, pulled out 3.5 m to ensure he was not stuck downhole. During these operations the pump pressure was fluctuating which could have been an indication of the coiled tubing breaking. Upon determining that the coiled tubing was not stuck the operator increased the hydraulic pressure to the injector and attempted to run past the assumed blockage. The injector head once again stalled at an odometer reading of 290m and at this time a gas leak was observed around the coiled tubing stuffing box. The operator attempted to pull the tubing slowly out of the well to obtain a better seal between the coiled tubing and the stuffing box and increased the hydraulic pressure to the stuffing box. These actions did not decrease the leak. The operator in conjunction with the drilling supervisor decided to close the slip and tubing rams in the upper set of BOPs, which reduced, but did not stop the leak. The tubing and slip rams were opened to attempt to pull out of the hole, however after pulling about one meter the gas leak became stronger, and further attempts to control the leak using the pipe rams were unsuccessful. It was decided to cut the coiled tubing using the shear rams of the upper BOP, pull out of the stuffing box and close the blind rams, which stopped the leak. The lower Shear rams were closed as an additional barrier. To establish the status of the Xmas Tree, closing of the swab valve was attempted and at 114 turns of a required 188 turns the gate valve met resistance. Subsequent X-rays of the riser revealed that the coiled tubing had been packed into the cross sectional area of the riser, which was later confirmed when the riser was rigged down and six strings of coiled tubing were found in place. The coiled tubing operator believing he was at 290 m was never deeper than 112 m. Due to unsuccessful attempts to bullhead and lubricate the well dead, it was decided to freeze the crossover between the Xmas Tree and the lower BOP. The riser was removed and a gate valve installed and tested. The remainder of the coiled tubing was then fished successfully with a snubbing unit.

1.9.3

Conclusions And Recommendations The gas leak could have been avoided if the hydraulic pressure to the injector head motors had been limited to less than that required to break the coiled tubing, or if better instrumentation in the control unit had helped the operator to realise that an obstruction had been encountered and the coiled tubing was breaking. Indications of possible coiled tubing failure should have been identified from the fluctuating pump pressures, however, probably due to inexperience on the part of the operator these were not picked up on at the time.


67


68



CONTENTS

1.


1

1.1

SNUBBING OPERATIONS

1

1.2

HWO OPERATIONS

5

1.3

THE RIG UP

5

1.4

WELL CONTROL DURING NORMAL OPERATIONS

7

1.5

SNUBBING EQUIPMENT 1.5.1 Hydraulic Jack 1.5.2 Guide Tubes 1.5.3 Slips

10 10 10 14

1.6

SNUBBING PRESSURE CONTROL EQUIPMENT 1.6.1 Stripper Bowl 1.6.2 Annular BOP 1.6.3 Stripping BOPs 1.6.4 Ram Type BOPs 1.6.5 Shear and Seal BOPs 1.6.6 Containment Devices in the Workstring

16 16 18 20 20 24 26

1.7

BLOWOUT PREVENTER CONFIGURATION 1.7.1 Scope 1.7.2 General Information 1.7.3 Procedure 1.7.4 Surface Lines and Manifolds 1.7.5 BOP Control Skid

31 31 31 31 39 39

1.8

OPERATIONAL CONSIDERATIONS 1.8.1 Pre Job Checks and Safety Procedures 1.8.2 Opening the Well 1.8.3 Crossing the Balance Point 1.8.4 Pulling Out of Hole With String 1.8.5 Emergency Response Procedures 1.8.6 Gas Wells 1.8.7 Combined Wireline/Snubbing Operations

39 39 41 41 42 42 43 44

1.9

SPECIFIC CONTAINMENT PROBLEMS 1.9.1 BOP Sealing Element Leak 1.9.2 Check Valve Failure 1.9.3 Tubing Pinhole 1.9.4 Changing the Stripper Rubber 1.9.5 Loss of Power

45 45 46 46 47 47


i


ii



1.


1.1

SNUBBING OPERATIONS Snubbing is performed by introducing an internally plugged pipe into a live well using BOPs to obtain an external seal around the pipe. The pipe is filled with fluid while running in to prevent collapse. The top of the pipe is run open. Snubbing is used for a variety of operations when it is not desired, or possible, to kill the well, including: • • • • • • • • • • • • • • •

Pulling and running completion strings Running concentric completions inside existing production strings (sometimes called insert strings or velocity strings) Milling and washing below production tailpipe Through tubing gravel packs Cleaning out proppants after frac jobs Fishing stuck or lost tools, ball valves, coiled tubing, etc. Spotting and pumping acid and cement Cleaning out obstructions inside tubing, casing, drill pipe and DST strings Well control problems on drilling and workover operations Well abandonment Perforating and re-perforating - particularly using very long TCP guns Running and pulling wireline and other mechanical tools - particularly in highly deviated wells Wells that cannot be killed because of heavy cross flow between zones or other downhole problems that cause inability to hold a full column of fluid Low pressure wells that require a kill fluid weight below that of sea water. These are usually gas wells Underground gas storage caverns (such as Immingham and in Eastern Germany). These manmade holes in the ground full of gas cannot be killed.

Snubbing operations use the BOPs either singly or in pairs for primary well control depending on the wellhead pressure, well conditions, pipe used and nature of work being undertaken. On very high pressure wells, provision may be made for backup BOPs and they may be initially provided for each size of pipe if a tapered workstring is to be used. This can lead to large numbers of BOPs, up to perhaps 10, being used. Snubbing unit configurations are very flexible and are tailored to the individual requirements of each job. Since the snubbing unit jack is positioned above all the pressure containment devices, the BOPs must be rated for the particular task to be undertaken (5,000 psi, 10,000 psi, 15,000 psi etc.). Of the 60 or so snubbing units outside of North America nearly all are different in size and make etc., and there is no such thing as a standard unit.


1


Figure 1 - Typical Hydraulic Workover Layout (foot print)

2


OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL 1.1.1

Rig Assist Unit (Mechanical) The first snubbing unit was designed in the 1920s by Mr H Otis to enable a drilling rig to snub pipe under pressure into a well. This unit is described as a mechanical or rig assist unit. (Refer to Figure 2) The rig assist units is rigged up on the rig floor and is only used in the pipe light mode. When sufficient pipe weight is achieved, the rig assist unit would be rigged down and further snubbing operations are continued with the rig stripping the rest of the pipe into the well. The rig assist unit is operated by 2 cables attached to the travelling block of the hoist drilling rig with each end of the cables passing around the pulleys on the base platform (or rig) of the unit and being attached to the travelling snubbers (Slips). The travelling snubbers are kept in position by re-positioning cables that pass around sheaves attached to the derrick structure and which have counter weights attached to them. These weights are sufficient to hold the travelling snubbers aloft and to maintain tension on the main snub cables.

1.1.2

Rig Assist Unit (Hydraulic) Recently hydraulic rig assist units have been built to enable rigs to trip pipe whilst under balanced drilling. Unlike a remotely operated short stroke unit , they are installed below the rig floor on top of the rigs BOP stack. They are only used for the first or last few strands of drill pipe when the up ward force from the well pressure is grater then the downward force from the pipe weight (pipe light mode)


3


Figure 2 - Rig Assist Rig Up

4



1.2

HWO OPERATIONS HWO operations are undertaken for a variety of reasons, including: • •

Remote locations where a conventional derrick is impossible to obtain, expensive or difficult to rig up or transport Offshore platforms where there is no derrick.

HWO operations can include: • • •

Full workovers Clean out, squeeze-off, re-perforating, deepening etc., in the production zone Running or pulling ESP completions and control lines which cannot be done on a live well as the closure of any BOPs would damage them.

HWO operations are conducted in the same manner as snubbing operations although fewer BOPs are used with primary well control being the kill fluid or mechanical plugging of the well. In all operational aspects, the snubbing unit performing HWO operations is a portable workover rig and normal well control procedures apply. A typical rig up would only include: • • •

1.3

Blind/shear rams Pipe rams Annular BOP.

THE RIG UP HWO/Snubbing units are rigged up directly onto the Xmas Tree for through tubing work, or onto the wellhead, after removal of the Xmas Tree, if completion components are to be pulled or run. They are rigged up on drill pipe if required for washing out. The equipment is rigged up as individual lifts or sub assemblies and directly nippled up onto the tree/wellhead or previous component. The normal maximum lift is of the order of 6 tonnes for a larger jack and does not usually cause problems. If a very tall rig up is required due to the number of BOPs in use, there are occasionally problems with the maximum reach of a platform crane. Where this is the case, it is sometimes necessary to take a portable rig up crane with the unit although this adds to the rig up time and costs. All the equipment is transported in baskets or on skids and it is true that a full short stroke unit, including all it’s auxiliary components, for North Sea use can occupy fully the deck of a supply ship. Once rigged up, however, most of the equipment is on the well and the transport baskets can be back loaded for storage. As the rig up progresses, it is a requirement in the North Sea to build scaffolding around the BOPs and window/jack for access. This is always done for one off jobs but if it is planned to undertake a multi well campaign, it can often be cost effective to have built transport frames around the BOPs which also act as scaffolding after rig up. Similarly, the window and jack can be equipped with frames which bolt on around them and which act as platforms for an individual platform. The design of the individual frames is dependant upon rig up heights and platform layout. There is no reason why a short stroke unit cannot be rigged up inside the derrick of a drilling rig. (Refer to Figure 3)


5


Figure 3 - HWO/Snubbing Unit Rig Up

6



1.4

WELL CONTROL DURING NORMAL OPERATIONS Hydraulic Workover (HWO) is performed using the equipment in a workover function on a dead or plugged well. For this reason, primary well control is by means of a kill fluid and normal rig BOP stacks and procedures are utilised. A spool piece would be inserted just above the BOPs for connection of a hole-filling pump and to a trip tank and normal tripping well control procedures would be followed. A typical scenario may be as follows: The unit is rigged up on a derrick less and facility less platform in the North Sea. It is required to change out the completion due to a leaking tubing retrievable SCSSV. After the removal of the Xmas Tree, the unit has been rigged up on the top of the well head with 1 shear/blind ram, 1 pipe ram and 1 annular BOP. A full set of mixing/pumping/circulating equipment has been taken off shore and rigged up. Well control has to be achieved in two areas: • •

Tree removal Whilst pulling the completion.

In order to remove the Xmas Tree, it is normal practise to have two mechanical barriers (i.e. plugs) and one fluid barrier (i.e. kill fluid or pill) in the well. This is no different to any conventional workover rig. While pulling the completion the plugs will have been removed and well control will rely on the kill fluid. The BOPs remain as a precaution for external pipe sealing should the well kick (i.e. if well is swabbed), as does the TIW valve or inside BOP for the pipe. The BOPs are controlled from the work basket with a duplicate set on the BOP skid which is normally situated close to an escape route. Very often when working as an HWO unit, the stripping rams and stripper bowl will not be rigged up or used and so the option of snubbing, should the well kick, is not available. Snubbing is performed on a live well and uses BOPs and other mechanical devices as it’s means of well control. In this respect, the principles are exactly the same as with coiled tubing. A typical scenario might be as follows: The unit is rigged up on a large offshore platform beside a derrick doing a normal workover. It is required to wash out scale in the perforations and rat hole. The SIWHP prior to the well scaling up was 2,850 psi. The unit has been rigged up on top of the Xmas Tree with, from bottom to top, 1 shear/blind ram, 1 pipe ram, 2 stripping rams, 1 annular BOP and a single element stripper bowl. The riser between the Xmas Tree and the BOPs is long enough to accommodate the BHA of the mill/under reamer/mud motors and BPVs. The choke and kill lines are connected to the rig circulating system and cement pump via a choke manifold.


7

OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL A stand alone high pressure, high volume skid mounted triplex pump may be included as part of the rig up and would be used for the following purposes: • • • • • •

Standby for well kill operations Work string fill up Conducting work string pumping operations Pressure testing the pressure control equipment Circulating hydrocarbons out of the work sting before rigging down Pumping sand wash fluids during a sand cleanout operations

Being a live well job, well control will be maintained by means of the BOPs at all times. Whilst running in with the clean out string, the wellhead pressure is sufficiently low to enable the stripper bowl to be used. The two BPVs in the workstring prevent flow back up through the tubing. Once below the tail pipe, the rig cement pump is used to circulate down the tubing, under reaming down with returns to the rig choke and de-gassers. Well control is initially achieved by use of the annular BOP and stripper bowl with the stripping BOPs and stripper rubber being used when the rat hole is reached. Having finished washing out, it is discovered that the BPVs are both leaking so the pump down plug is dropped and seated. With full wellhead pressure restored, the pipe is pulled using the stripper rams for well control. The BOPs are controlled from 3 locations: • • •

The work basket From the BOP skid From a remote panel situated near by

Although in conventional well control terms, a drilling rig uses the kill fluid as it’s primary well control, the descriptions during live well work applying equally to wireline and coiled tubing are slightly different. In live well terminology, we speak of containment devices which are split into primary, secondary and tertiary well control devices. A containment device becomes a barrier when it has been operated/closed. (Refer to Figure 4) Primary well control containment devices/barriers are those used in the minute by minute performance of the work such as stripper rubbers, annular preventers (bags, spherical, hydrils, etc.), stripping Rams. Secondary well control containment devices/barriers are those used back ups to the primary devices such as pipe rams, variable rams, blind rams, shear rams and blind/shear rams. Tertiary well control containment devices/barriers are those used solely in an emergency such as safety heads placed immediately above the Xmas Tree/wellhead, consisting of hydraulically boosted blind/shear rams capable of cutting large strings of pipe with braided line inside. Also called shear/seal rams.

8



Figure 4 - Well Containment Devices


9


1.5

SNUBBING EQUIPMENT

1.5.1

Hydraulic Jack The jack is the assembly of hydraulic cylinders and slip bowls which enables the pipe to me moved in or out of the well. Situated at the top of the rig up, with the work basket attached to the top of it, it has the work stations for the crew. Attached to it are the arm for the power tongs, the gin pole and the counterbalance winch. On the top of the cylinders is the travelling head which carries two slip bowls and the rotary. By means of valves, the hydraulic circuits can be set up to provide different speeds and hence powers for the travelling head. The hydraulic fluid can be directed into all 4 cylinders or optionally into 2 of the cylinders. On some units it is possible to select which two opposing legs whereas on others, there is no choice. This is called 4 leg and 2 leg operation. It is also possible to select whether the hydraulic fluid being returned from the un-pressurised side of the cylinders is directed back to the tank or added to the fluid going to do the work in the pressurised side. This is called regeneration and is equivalent to high and low gearing. (Refer to Figure 5) There are thus 4 operating modes: 2 leg high (with regeneration)

Fastest but lowest power

2 leg low 4 leg high (with regeneration) 4 leg low

Slowest with highest power

It is normal to start the job in 2 leg high and, as the pipe weight increases, change into the other modes as required. It is a very simple job of turning a valve or two in the work basket to change from one mode to another. The stroke of a jack depends on the make, but most in the North Sea have a 10 ft working stroke. 1.5.2

Guide Tubes The higher the well pressure, the greater the force pushing up on a given piece of pipe being snubbed into or out of the well. Since the pipe coming up through the window and the jack is only restrained at a distance from the stripper bowl, there is a problem with potential buckling of the pipe which would bend the pipe out of the side of the window or jack. For this reason, in higher pressure wells, guide tubes are placed in the window and in the jack. These restrain the pipe and stop it being buckled out of the side. The guide tubes can be easily inserted or removed and the one through the jack is in two pieces. One piece is sitting in the jack, hanging from a level with the top of the legs, and the other (inner) piece is hanging from the travelling head and sliding up and down in the lower section. (Refer to Figure 7)

10



Figure 5 - Multi Cylinder Jack Assembly


11


Figure 6 - Short Stroke

12



Figure 7 - Spline Tube And Snubbing Guide Tube Assembly


13


Slips Travelling slips are attached to the travelling head and consist of one bowl for pipe heavy and one bowl for pipe light. Almost always hydraulically operated, the two bowls are the same with the pipe light bowl facing down. Similarly, the stationary slips are attached near the bottom of the jack, but do not move. In high pressure wells, it is normal to use an extra set of stationary snubbers for safety. (Refer to Figure 8 and Figure 9)

Figure 8 - Travelling Slip Bowl Assembly (4/16 ins bore)

14



Figure 9 - Slip Operating Sequence (light pipe running in)


15


1.6

SNUBBING PRESSURE CONTROL EQUIPMENT

1.6.1

Stripper Bowl The stripper assembly is a special device which is used for the following: • • •

Primary well control with low wellhead pressure work Pipe cleaning on pulling out Prevents dropping of debris down the wellbore whilst tripping.

Stripper bowls are available with both single elements and dual elements. They are rated to an absolute maximum of 3,000 psi. although in practice one would not rely on the stripper rubber as the primary well containment device above 2,500 psi. wellhead pressure. The use of the stripper bowl allows for the continuous handling of pipe with a tapered upset or no upset. It is normal to change the stripper rubber(s) during a job. Wear on the rubbers is affected by: • • •

Wellhead pressure Lubrication at the rubber External pipe roughness.

In the dual element stripper, pressure equal to half the wellhead pressure is kept between the rubbers by a small pump and reservoir. This is to halve the pressure on each rubber and thus keep within its working range. The single element stripper bowl is effectively half of a dual stripper bowl. More recent snubbing units, particularly in the North Sea, tend to have single element stripper bowls. Each snubbing unit has a stripper bowl of whichever kind and cost does not usually dictate changing it. (Refer to Figure 11)

16



Figure 10 - Stripper Bowl

Figure 11 - Dual Stripper Bowl


17


Annular BOP The annular BOP is identical to a standard BOP used in drilling operations although normally of a smaller size. A typical BOP would be a Shaffer or Cameron 11” 10k or 71/16” 10k. The pressure rating is specified according to the wellhead pressure. (Refer to Figure 12) The annular BOP is used when the normal ram type BOPs cannot seal around something due to its enlarged size, such as a side pocket mandrel, blast joint, slip joint, etc. Figure 13 shows a Cameron ‘DL’ annular preventer.

Figure 12 - Annular BOP

18



Figure 13 - Cameron ‘DL’ Annular Preventer


19


Stripping BOPs Stripping BOPs are standard ram type BOPs as used in drilling operations with special elements to enable them to seal on moving pipe. (Refer to Figure 14) These BOPs are used as the primary well control when the wellhead pressure is greater than the stripper bowl can handle alone i.e. above 2,500 psi. The pressure rating and size are determined by the wellhead pressure and work to be undertaken. They are always used in pairs to enable a tool joint to be worked through while still retaining a seal around the pipe. They are always furnished with an equalising loop, with hydraulically operated valves controlled from the BOP console in the workbasket, and connected immediately below each BOP. A bleed off line, with similar control valves, is connected between the two BOPs. (Refer to Figure 15) It is normal practise to have to change the inner seals with their inserts during the course of the operation. The life of the inserts is affected by: • • •

Pipe external condition Well pressure Speed of running of the pipe.

It is normal practise when using stripping rams to also use a stripper bowl. This is to provide: • • •

Barrier for egress of hydrocarbons Pipe wiper Debris barrier.

The spool between the two BOPs must be of sufficient length to allow the pipe to be pulled slowly through the BOPs whilst sequentially opening and closing them. It is traditionally 4 to 6ft long. The spool and equalising loop are of a fixed size on any particular unit and pipe pulling speed is reduced while the tool joint passes through the BOPs. It is not necessary however to stop pulling for this operation. The operation of the two BOPs is carried out in reverse order when pulling out of the hole. Figure 16 shows the stripping sequence while running in the hole 1.6.4

Ram Type BOPs These are normal drilling type BOPs and are used as pipe rams or as blind, shear or blind/shear rams. It is normal practise to have one BOP in the stack dressed for each size of pipe in use since there is no way to redress the rams during the job. Often called the safety BOPs, they are normally only used when changing elements in the stripping rams, annular or stripper bowl, or when the pipe is stationary for a period of time. BOPs can be dressed with slip rams or variable bore rams as per job requirements.

20



Figure 14 - Stripping Ram Seals


21


Figure 15 - Pressure Control Stack Up

22



Figure 16 - Stripping BOP Sequence When Running In


23


Shear and Seal BOPs Now mainly replacing separate blind and shear rams, these are very often hydraulically boosted BOPs to enable them to cut anything that may be in the well (workstring with fish etc.) and then seal off the well bore. These BOPs are placed immediately above the wellhead but below any riser on offshore installations for some regulatory bodies. (Refer to Figure 17) Where separate blind and shear rams are used, the choice of which to place below which is often dictated by well conditions or operator preference. For most snubbing jobs the shear is commonly placed below the blind since the pipe may very well be trying to push out of the well bore at the time it is required to be cut. Conventional shear rams may not always cut the workstring completely (for example if it is required to cut a BHA with a fish inside) and it may be necessary to RIH one or two joints before operating normal shear rams in this case.

24



Figure 17 - Shear Seal Rams


25


Containment Devices in the Workstring There are two main types which are commonly used: • •

Check valves Pump down plug and landing nipple.

Check valve - Since the pipe is open at all times to surface, two check valves or back pressure valves are always placed at the bottom of the string, above the BHA. They allow fluid to be pumped down the string but inhibit flow up the pipe. (Refer to Figure 18) Both ball and seat check valves and flapper valves are used. Since the flow area through these valves is fairly small, if there is any scale in the tubing it is quite easy for debris to plug them off. Two operations should be performed to minimise the risk of this happening: • •

Tubing is to be inspected and rattled immediately prior to going offshore When filling up the string the valves are pumped through for a barrel or two. This is to ensure they are still open and to clear out any build up of debris.

Pump down plug and landing nipple - In jobs involving large amounts of pumping it is not uncommon for both the back pressure valves (BPVs) to be washed out. A small but normal completion type landing nipple is always placed above the BPVs so that in the event of a leakage through the BPVs, a plug can be pumped and seated in the nipple prior to pulling out with the pipe. The pulling of a wet string is a favourite time for snubbers although it is normal to pump the pipe full of water prior to pumping the plug so as to minimise pollution from hydrocarbons or corrosive brines. (Refer to Figure 19) A very wide variety of BHA devices can be used as a means of internal primary well control including: • •

Pump out plugs or pump out BPVs Sliding side doors or sliding sleeves coupled with positive plugs. This is mostly to allow reverse circulation.

As well as these items on the bottom of the string, there are always available in the work basket safety valves (TIW stab in valves) and/or inside BOPs which can be used in the event of a tubing/BHA break or leak in the tubing string. An example of a stab-in valve is shown in Figure 20, and examples of BPV bottom hole configurations used for inside pressure control are show in Figure 21

26



Figure 18 - Check Valves


27


Figure 19 - Pump Down Plug And Nipple

28



Figure 20 - Stab In Valve (Fully Opening Safety Valve)


29

OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL Tertiary well control is provided by shear/seal bop system, primary and secondary inside well control is shown below:

Figure 21 - Inside Well Control

30



1.7

BLOWOUT PREVENTER CONFIGURATION

1.7.1

Scope Blow out preventers are pressure containing, hydraulically controlled, wellhead equipment. When used with snubbing units, they are also a primary structural component of the unit.

1.7.2

General Information The primary function of BOPs is to contain well pressure. BOPs are essential in well servicing applications to allow movement of pipe in and out of the well under, sealing off of the wellbore, and controlling flow of wellbore gases and fluids. BOP rams may be set up as blinds (to seal the wellbore) safeties (to maintain seal around the pipe), strippers (to permit movement of the pipe through the rams while sealing), cutters (to cut the pipe), or slip rams (to hold the pipe). A minimum, of three BOPs are usually rigged up. When the well pressure exceeds 3,000 psi (or the working pressure of the stripper bowl) or when running collared pipe and a stripper rubber cannot be used, it then becomes necessary to strip the pipe through the BOPs. The quantity of BOPs and valve arrangements will depend on well conditions, pressures, workstring configuration, and service operations. While most major oil companies have their own arrangement for various conditions, it is the supervisors responsibility to determine if the arrangement is satisfactory and to point out ways to improve it.

1.7.3

Procedure • • • •

• •

•

The wellhead must have a minimum of two functional master valves, two blind BOPs or a combination of both. (Exception - dead well workover) A minimum of three BOPs will be rigged up on all snubbing jobs (Exception dead well workovers) The BOP working pressure rating must be at least 20% higher than the maximum anticipated shut in well pressure or rated at or above the working pressure rating of the wellhead equipment For well pressure of 0 to 3,000 psi and one pipe size, the minimum required BOP stack containing three preventors (Refer to Figure 22). Additional equipment maybe required depending on job conditions. Threaded connections up to 2” are acceptable on valves, loops or outlets When running more than one pipe size, at least one safety ram will be included in the stack below the strippers for each different size pipe being used. (Refer to Figure 23) Additional safeties may be required for higher pressure For well pressures of 3,000 to 5,000 psi an additional safety ram will be included in the BOPs stack for each pipe size. (Refer to Figure 24) Threaded connections up to 2” are acceptable on the valves, loops or outlets. Additional equipment may be required depending on job conditions For well pressures of 5,000 to 10,000 psi a minimum of six preventors including two strippers, two safeties, blinds and cutters with double valves will be used as per Figure 25. No threaded connections are permitted. Additional equipment may be required depending on job on job conditions


31

OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL • • • • • • • •

• • •

32

For well pressures over 10,000 psi and for one pipe size, a minimum of seven preventors (Refer to Figure 26). No threaded connections are permitted. Additional equipment may be required depending on job conditions When well pressures exceed 3,000 psi a doubled valve drilling cross should be used for return and surface kill operations. This may prevent BOP damage and potentially hazardous situations Use a double valve cross for returns when the pressure exceeds 3,000 psi line pipe connections on wellhead equipment are not permitted when well pressures exceed 3,000 psi When well pressure exceeds 3,000 psi a minimum of one set of BOPs for each pipe size will be rigged up below the return A choke bean or choke nipple will be used in the equalising loop and bleed-off line New ring gaskets will be used whenever flanging up BOP connections All flanges must be made up using B-7 studs and 2-H nuts The opening of hydraulically controlled valves located on the return cross and exposed to pressure differentials should be avoided. Equalising pressure across valves prior to opening is preferred to avoid pressure cutting. Inside valves should only be operated to repair downstream components When shutting down at night with pipe in the hole, shut and lock a minimum of two BOPs. The bottom safety BOP should only be closed when needed for BOP repairs or in emergencies. All side outlets on bottom safety BOPs must be blind flanged H2S certified equipment must be used when working on any well that contains H2S as per NACE MR-01-75. It is the supervisor’s responsibility to make sure all valves and BOP parts are H2S certified.



Figure 22 - Standard 41/16” 10,000 BOP Snubbing Stack For 0 - 3,000 psi


33


Figure 23 - Standard 41/16” 10,000 BOP Snubbing Stack For 0 - 3,000 psi And A Tapered String Of 1” And 11/4” Pipe

34



Figure 24 - Minimum Snubbing Stack For 3,000 - 5,000 psi


35


Figure 25 - Minimum BOP Stack For 5,000 - 10,000 psi

36



Figure 26 - Minimum BOP Stack For Pressure Over 10,000 psi


37


1.8

RECOMMENDED HYDRAULIC CIRCUITS WITH ACCUMULATORS Figure 27 Illustrates the recommended slip/BOP hydraulic circuits for operating up to four casing/tubing BOPs from the basket (work platform) and additional casing base BOPS console. Console Accumulators combined with auxiliary accumulators must be of sufficient capacity to comply with requirements stated within the recommended practice.

Figure 27 - Recommended Hydraulic Circuits With Accumulators

38



Surface Lines and Manifolds The requirements for pumping and circulating facilities are different for each job, but all operations require some form of pump. Required facilities can vary from: • • •

A complete mixing and killing facility on an offshore satellite with a large choke manifold A hook up on an offshore platform direct to the existing facilities A remote land job requiring basic pressure testing and pumping facilities only.

Normal hook-ups to the stack are choke, kill and bleed off lines. On all these lines, main pressure control is via hydraulically operated valves, controlled from the workbasket, with a manual valve as a backup to each. In principal this is as per normal drilling practise. On some dead well operations a trip tank and fill up line connections would be made to the top of the stack below the window for use while tripping. 1.8.2

BOP Control Skid All North Sea HWO/snubbing units have a BOP control skid separate from the main power pack. All BOP skids derive their primary power supply from the power pack and have a separate air or electric power supply as a back up. Basic controls are provided in the workbasket for most or all of the BOP functions. Some units do not have the shear/seal control in the basket. A duplicate set of controls is provided at the BOP control skid although this does not always include the stripper rams. On some jobs, notably where the unit is rigged up alongside a drilling rig offshore, the operator has asked for a third panel controlling only the secondary and tertiary controls to be placed beside the rig’s panel at an escape route.

1.9

OPERATIONAL CONSIDERATIONS Due to the comparative complexity of the equipment and the requirement for an in depth knowledge of the operation of the equipment on a live well, it is normal practise to have a snubbing supervisor (the equivalent of a pusher) on each snubbing crew. It is his responsibility to ensure the safe and correct procedures are followed at all times and particularly when using stripping BOPs, crossing the balance point, etc. In all the following cases it is assumed that snubbing or ‘live’ well work is being considered.

1.9.1

Pre Job Checks and Safety Procedures In general, there are no items of a snubbing unit which require special procedures prior to sending offshore. The normal requirements of modern certification levels and maintenance standards, as found in the North Sea, should ensure that the equipment is in first class order to undertake the task required. In more remote areas of the world, certification and maintenance standards should be checked more closely.


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OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL After the unit is rigged up on the well, all features are function tested. The stack is then tested inclusive of all connections, lines, valves and manifolds. To test the rams it is necessary to pick up one or more joints of pipe and run them into the stack so that the BOPs etc. can be tested. These joints will have to be plugged either at the top, or bottom, and must be restrained from being pumped back out of the well. Before commencing a job, it is important that the following have all been checked: • There are sufficient spares for the job i.e. Stripper rubbers, slip dies, BPV spares, BOP seals and elements, pump down plug seals • The stabbing or TIW valves are in the work basket • The unit is rigged up vertically • The guy wires have equal and sufficient tension • Tubulars are clean and free of scale - inside and out • All snubbing unit functions operate correctly • All BOPs and valves operate correctly • BOP accumulator skid remote controls operate correctly • Power pack functions correctly • A plan has been formulated and understood by all to cover shutdowns and emergencies. For the rig up, a typical pressure test sequence might be as follows: • • • • • • • • • • •

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Surface lines and manifolds Inner (manual) and outer (hydraulic) valves at stack connections Shear/seal BOP and riser After picking up a joint (or 2) of pipe with BPV on bottom, lower pipe ram (this also tests BPVs) Upper pipe ram Lower stripping ram Upper stripping ram Equalising loop and valves (hydraulic and manual) Annular Stripper bowl TIW and stabbing valves, etc.



Opening the Well Introducing the tool string into the wellhead is one of the most delicate phases of a snubbing operation. It is at this time that the string is at its lightest and hence the upward force trying to eject or buckle the pipe is at its greatest. Great care must be taken to ensure that the inverted, or snubbing, slips have taken a proper ‘bite’ on the pipe, with the use of a clamp or dog collar below the slips often required. It is remarkable how far 1 or 2 joints of 11/2” tubing and a few BPVs etc. can fly when they are not properly set in the slips! When introducing the pipe into the well, the stripper rubber is first inserted and secured. The BHA is then made up onto the first joint and pushed through the rubber. The ram(s) can then be closed and the well opened up after equalising across that which is closed. It is normal practise to use one stripping BOP or the annular to centralise the BHA and stop it hanging up in the stack and tree.

1.9.3

Crossing the Balance Point In theory, this is a single point but due to friction both downhole and in the stack, this phase can last for several hundred feet. The technique used is such that as the pipe gets close to the balance point, by filling with fluid, it can be made rapidly heavier and thus pass through the balance point. During this phase it is very difficult to get the slips to bite on the pipe as the pipe appears to have no weight. The use of two stationary slips together (regular and inverted) or the use of two travelling slips together is to be avoided as this can lead to jamming of the pipe in the slips. There are various methods of shortening and helping the balance point transition, but no matter what is done there will nearly always be a few tricky joints. Pipe is usually filled (to prevent collapse) depending on well and pipe conditions and the procedure for crossing the balance point running in is: • • • • •

At first sight of reaching balance point, stop Keep pipe ‘hanging’ in travelling snubbers Close stationary heavies Fill pipe Assuming pipe has now crossed balance point, change travelling snubbers to regular slips and continue running in hole.

In rare cases this will not have been enough to cross the balance point completely, in which case either: • • •

Flow the well to reduce CITB Slug the pipe with a heavy fluid Continue running in hole using dog collars.


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OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL During pulling out the pipe is full of fluid and since it is not possible to empty the pipe to reduce its weight, the well pressure can be acted upon. Either: • •

Flow the well to increase the length of the ‘heavy’ pipe phase and then shut in again. The balance point will have been passed If conditions permit, a slug of heavy fluid can be circulated round the outside of the string to reduce CITB.

In some circumstances, usually caused by pressure changes in the well, it may be found that once the balance point has been crossed it is found again after a few more joints and then finally for the third time. Each time the same procedures are adopted. 1.9.4

Pulling Out of Hole With String It is important that as the last few joints being pulled are reached, there is an indicator in the tool string to warn the crew that the bottom of the string is approaching. This is usually achieved by spacing out the landing nipple with a joint of pipe between it and the BPVs so that when the nipple is at the work basket the master valve or blind ram can be closed and the stack de pressurised. If a very long BHA has been run or a fish has been caught, the landing nipple might be directly on top of the top BPV.

1.9.5

Emergency Response Procedures Job Suspension On some jobs, only 12 hour operations are planned and the routine at night is usually as follows: • • •

Install closed stabbing valve having filled tubing Close safety rams and manually lock Tighten dogs on hanger flange.

Some operators like to have one of the snubbing hands watching over the unit at night during shutdowns. ESD Systems It is to be noted that if the main hydraulic power pack on a snubbing unit is linked to any platform shutdown system more problems than advantages will occur. It is imperative that the well is made safe in an emergency. Just as with a drilling rig, if the snubbing unit is linked to the ESD system, on a shutdown the pipe can be left up in the air with no way of closing it in. There is also the possibility that a joint of pipe hanging on the second winch will start to slip (it is a hydraulic winch) and could cause injury.

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OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL Shutdown The detailed actions will vary from installation to installation and job to job depending on the level of shutdown and whether abandonment is envisaged. At the very least, the top of the pipe will be run into the rotary in the work basket so that an inside BOP or stabbing valve can be installed, with one or more of the BOPs closed and possibly manually locked. Abandonment In the event of abandonment, a plan will have to be formulated to cover whether or not to close the blind/shear rams and/or the SCSSV (if it is in the well and can be closed). 1.9.6

Gas Wells Sweet Gas Wells If a dry sweet gas well is to be worked on, special consideration must be given to the hydraulic connections of the snubbing unit (of which there are many). Avoidance of any spillage is especially important as dry gas and hydraulic oil or grease/dope are a very volatile mixture. Any oil or dope building up around the stripper rubber or on top of the stripping rams soon becomes heavily contaminated with gas and is potentially dangerous. These wells are fortunately rare and consideration is always given to injecting a small amount of water into the well prior to running the pipe. It is important to keep the stripper rubber or stripping rams well lubricated with water to obtain a good seal around the pipe. Sour Gas Wells Sour gas wells can be found with H2S concentrations up to 40%+. Normally not dry gas. The wells require extreme caution in all operational phases to ensure no escape of gas is likely. Usual precautions might include: • • • • • • • • •

Use of top quality H2S rated, inspected and checked equipment only Flare line laid Provision of working air supply and masks from ‘quads’ on deck for crew Doubling up of BOPs to avoid changing elements and hence exposing personnel to the risk of H2S Daylight hours only to ensure adequate visibility for maintenance and repair No work during periods of no wind Essential personnel only All workers checked for perforated ear drums Rehearsed safety/escape drills.


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OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL Although these jobs are special, they have been performed many times with complete safety. As with all work, planning is paramount. A typical job might involve drilling out a DST string that has become plugged with sulphur. 1.9.7

Combined Wireline/Snubbing Operations Slickline or electric line operations can be conducted through the jack of a snubbing unit either by: •

Rigging up the wireline lubricator on the workstring

•

Screwing an adapter into the stripper bowl and connecting a riser to the workbasket.

or

In both cases normal wireline well control considerations apply, with either a master valve placed on top of the workstring or the snubbing unit blind ram used as a master valve.

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1.10

SPECIFIC CONTAINMENT PROBLEMS During an HWO operation there is always a possibility that the well will kick as with any conventional derrick operation. In the North Sea, all company supervisors, snubbing supervisors, and snubbing chief operators (equivalent to driller) have approved well control certificates and are capable of handling such occurrences. In more remote areas of the world where standards are not so high, the experience and training of supervisors and crews is important to enable them to react to any problems that may occur. The following containment problems relate to snubbing operations:

1.10.1

BOP Sealing Element Leak Ram Type This can be considered as being in two categories: • •

BOP elements changed out as normal routine due to wear Leaks around elements occurring unexpectedly.

In the case of routine replacement due to wear (the stripping rams are susceptible to this). The procedure for changing inner seals is: • • • • • • • • • •

Stop running pipe, close heavies, travelling slips and insert stabbing valve Close safety rams and stripping rams With bleed off closed, open lower stripping rams. Keep equalising line closed Open bleed off and check safeties are holding Close annular, open upper stripping rams Change all 4 inner seals Close lower stripping rams Open safeties to check lower stripping rams are holding Close bleed off, open equalising line and check top stripping rams. Open lower stripping rams Open annular and prepare to RIH.

In the case of unexpected leaks, all the BOPs above the safeties can be repaired by closing the safeties, checking they are holding and then working on the stack. Annular In the case of a leaking annular, it may be necessary to pull back out of the hole, close the blind rams and rig the jack off the well before being able to open the bonnet of the annular. The annular should always start a new job with a fresh rubber and it is indeed a rare occurrence to have to change it during a job.


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OVERVIEW OF HWO/SNUBBING PRESSURE CONTROL Shear/Seal In the case of a leaking shear/seal, safety BOP or riser connection, the only choices are: • •

Pull back out of the hole, close or plug the wellhead Kill the well.

If the well being worked on is low pressure and the safeties will no longer hold pressure, the lower stripper BOP (which has seen little or no use) can be used as a replacement safety until the pipe is out of the hole. 1.10.2

Check Valve Failure It is not uncommon for the BPVs to leak if a lot of pumping has taken place. The procedure in this case is: • • • • • • •

1.10.3

Install stabbing valve and close same Place plug on top of valve Connect circulating hose to top of valve Open valve and allow plug to drop to nipple or pump it down Pump to seat plug Inflow test plug Pull out of hole with wet trip.

Tubing Pin Hole It is important that prior to using a workstring it should be properly inspected and rattled to minimise the chance of pinholes and scale. In some parts of the world where work strings are not well cared for, pinholes can sometimes be a problem. Usually pin holes are found on picking up the pipe for the first time and the crews will be looking out for them if the pipe quality looks poor. As the pipe is run the operator can feel each tool joint, as it goes through the stripper rubber, on his weight indicator. As this is the start of a new joint, most operators' first reaction to a sudden egress of fluids out of the top of the pipe is to pull back to the tool joint and back it out. The stabbing valve is then inserted and the leak stopped. If the above action has not cured the leak then it must have occurred downhole and the plug must be dropped and seated in the nipple to confirm whether it is the BHA or a tubing hole. If it is a tubing hole, it is often possible to slug the pipe with a heavy fluid and pull a wet trip back out of the hole. Multi-set Wireline bridge plugs are available which could be used to plug the tubing above the hole to enable the pipe to be pulled. In the worst case the well might have to be killed if the hole was very large. Any sudden leak occurring before pulling out after washing operations could indicate a washout in the string and will also require the same procedures.

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Changing the Stripper Rubber This is a routine operation, but opens up the topmost containment device, and is performed as follows: • • • • • • • • • •

1.10.5

Close the annular and lower stripping ram and check they are holding Back out the retaining nut and pull out the rubber(s) with a tool joint Hang off the pipe and close the safety ram Bleed off below the annular through the bleed-off line Break the joint in the window Install the new rubber by placing on the box and screwing in the pin Make up the joint, take the weight of the string and back out the hanger dogs Open the safety ram and run in to seat the rubber(s) Tighten the retaining nut Open the BOPs and RIH.

Loss of Power In the event of a power loss to the snubbing unit, the BOPs will not be affected as they are on an individual skid with two independent power supplies (e.g. diesel and air). The worst situation for a power loss to occur would be just after having made up a joint with most of it sticking up in the air above the work basket. If the integrity of the BPVs was in doubt the counterbalance winch could be rigged to run from the BOP skid and used to raise a man to install the stabbing valve.


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Well Intervention Presssure Control (IWCF)

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