Completion Design Manual (shell) 5hj22
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Completion Design
CONTENTS 1.
COMPLETION DESIGN
1.1
1.1
INTRODUCTION
1
1.2
DESIGN CONSIDERATIONS
1
1.3
COMPLETION AT THE RESERVOIR
5
1.4
PERFORATING 1.4.1 Gun Types and Perforation Methods
8 9
1.5
WELL INFLOW PERFORMANCE
13
1.6
VERTICAL LIFT PERFORMANCE
16
1.7
FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING
19
1.8
COMPLETION COMPONENTS DESCRIPTIONS 1.8.1 Re-Entry Guide 1.8.2 Landing Nipple 1.8.3 Tubing Protection t 1.8.4 Perforated t 1.8.5 Sliding Side Door 1.8.6 Flow Couplings 1.8.7 Side Pocket Mandrels 1.8.8 Sub-Surface Safety Valves (SSSVs) 1.8.9 Annulus Safety Valves (ASVs) 1.8.10 Tubing Hanger 1.8.11 Xmas Tree 1.8.12 Production Packers 1.8.13 Seal Assemblies 1.8.14 Expansion ts 1.8.15 Tubing 1.8.16 Sub-Sea Wellheads 1. 8.17 Examples of Single String Completions
24 24 25 26 26 27 29 29 31 34 34 37 40 45 48 49 52 54
1.9
DUAL COMPLETIONS 1.9.1 Examples of Dual String Completions
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Completion Design
1
COMPLETION DESIGN
1.1
INTRODUCTION In simple , 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 1:1 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) or 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 13 3/8 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 9 5/8 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: 1. for each casing string. 2. for the BOP equipment for the next section of hole to be drilled. 3. Sealing off the various annuli from pressure control purposes. 4. for the completion string. 5. for the Xmas Tree. 6. 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 1:2 shows a simplified schematic of surface wellhead sections. The letters shown represent a common way of representing annuli. A. The 95/8 ins or production casing string when we insert tubing in the well this would be termed the tubing/production casing annulus. B. The 95/8 ins and 133/8 ins annulus. C. 133/8 ins and 20 ins annulus.
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Completion Design
Figure 1:1- North Sea Casing Profile Example
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Completion Design
Typical OBS drilling sequence
Figure 1:2 – Typical Surface Well Head 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 it reservoir fluids into the borehole at the depth of the reservoir (or reservoirs). 1) Openhole {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; See Figure 1:3a. This type of completion is ideal where the reservoir rock is of the appropriate mechanical strength i.e. is consolidated and 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 costs. Open hole completions offer no scope for isolating individual zones for production, stimulation or remedial work. However, this bottomhole 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. 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 wirewrapped casing (or tubing) which is hung from the production casing and sealed into it; See Figure 1:3b. The slots or wire wrapped pipe prevents sand from entering the wellbore. 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 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 bottomhole completion type has all the disadvantages of the open hole completion with the added cost of the liner and liner hanger thrown in. Its application is 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) Cased and Cemented Completions This is the most common type of bottomhole 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; See Figure 1:3c. 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 1:1.
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Completion Design BOTTOMHOLE ADVANTAGES COMPLETION TECHNIQUE Open Hole No perforating, no production casing, no cementing expense Minimum rig time
Cased and Cemented
Liable to "sand out" No selectivity for production or stimulation
Full diameter hole in the payzone improves productivity
Slotted Liner
DISADVANTAGES
No critical terpretation is required No perforating or cementing expense for the production casing
Ability to isolate is limited to the lower part of the hole No selectivity for production or stimulation
Assists in preventing sand production
Cost of slotted liner or prepacked screen
No critical terpretation is required
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 injection Cost of casing/liner and cementation Cost of rig time for longer completion period
Table 1:1- Bottomhole Completion Techniques -Advantages and Disadvantages
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Completion Design
Figure 1:3 – 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 openhole 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, See Figure 1:4, 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.
Figure 1:4 – 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"; See Figure 1:5a. 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 expands 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; See Figure 1:5b. 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; See Figure 1:5c. 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 (T) (run on tubing)
Figure 1:6 shows schematically the application of the three main perforating techniques. T 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, an Xmas 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. The guns can be jettisoned after firing and allowed to fall to the bottom of the well below the perforated interval. NOTE:
The completion requirement for a T system is to allow an appropriate sump for the guns to fall into.
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Completion Design The advantages of T 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 T 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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Figure 1:5 – Perforating Gun Types
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Completion Design
Figure 1:6 – Perforating Techniques
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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 designed string with tubing as the production conduit. An example of a DST string is illustrated in Figure 1:7. 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. Inflow performance relates to the movement or flow of fluid form 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 are 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 flowrate 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 1:8. 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.
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Completion Design
Figure 1:7 – Typical Drill Stem Test (DST) String
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A (Oil Well) - typical IPR showing Low Productivity. B (Oil Well) - typical IPR showing High Productivity. C (Gas Well) - IPR showing an Additional Pressure Drop caused by inertial and turbulent effects in the vicinity of the wellbore.
Figure 1:8 – Example of an IPR Curve
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Completion Design 1.6
VERTICAL LIFT PERFORMANCE Vertical lift performance (VPR) is concerned with the movement of reservoir fluids from the wellbore at the depth of the reservoir to the production choke on surface. VPR 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 1:9.
Figure 1:9 -Well Outflow and Inflow Systems
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Completion Design NOTE:
During production, critical flowing conditions are usually maintained at the choke
Intake Pressure (psi)
An example of VLP curves for various pipes Ids is shown in Figure 1:10.
Oil Flowrate (bopd)
Figure 1:10 –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; Figure 1:11. 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 1:11 – Matching VLP Curves with an IPR Curve
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Completion Design 1.7
FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING 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 1:1. The objective is to design a completion string for this well with the following basic functional requirements: • • • • • •
To provide optimum flowing conditions To protect the casing from well fluids To contain reservoir pressure in an emergency To enable downhole 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
NOTE:
The above functional requirements are not exhaustive.
A completion string that fulfils these functional requirements is illustrated in Figure 1:12. 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
Swab Valve
Master Valve
Figure 1:12 –Completion Design Example 1
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Completion Design The completion design of Figure 1:12 also addresses the other functional requirements of: • • • • • • • • •
Suspension of 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 1:2. 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 Tubing Hanger Barrier Installation Points Landing Nipples Tubing Hanger Pressure Testing Landing Nipples Pumping Operations Piping Manifold c/w Choke Table 1:2- Component Selection for Completion Example 1
NOTE:
Some components have dual functions.
NOTE:
This completion design utilises a permanent packer and tailpipe that is installed by wireline techniques prior to running the completion string (packer systems will be discussed later).
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Completion Design Completion Design Example 2 Figure 1:13 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 1:3: COMPONENT Tubing hanger
FUNCTION Tubing 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 Wellfluids Ensure Retrievability of All Components Landing Nipple Pressure Testing of Tubing String Barrier Installation Point Installation Point for Plug to Set Packer Perforated t Allows Flow of Fluid when Monitoring Reservoir Performance Landing Nipple (No-Go) Installation Point for Pressure/Temperature Gauges Re-Entry Guide
Allows Unrestricted Re-Entry of Well Intervention Tools Into the Tubing
Table 1:3- 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 1:13 – 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 1:12 and Figure 1:13. 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: 1. 2.
Bell Guide Mule Shoe
The Bell Guide; Figure 1:14, has a 45° lead in taper to allow easy re-entry into the tubing of well intervention toolstrings (i.e. wireline or coiled tubing). This guide is commonly used in completions where the end of the tubing string does not need to by the top of a liner hanger. The Mule Shoe Guide; Figure 1:14, 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 kick the tubing into the liner.
Wireline Entry Guide with Half Muleshoe Bottom
Wireline Entry Guide with Bell Bottom
Figure 1:14 -Re-entry Guides
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Completion Design 1.8.2
Landing Nipple A Landing Nipple, Figure 1:15 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 bottomhole pressure and temperature gauges
A No-Go Landing Nipple, See Figure 1:15, has a small shoulder located within the internal bore of the nipple for the purpose of preventing 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 No- Go 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 1:15 – 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 t This is a t 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 t A Perforated t, See Figure 1:16, may be incorporated in the completion string for the purpose of providing by flow if bottomhole pressure and temperature gauges are used for reservoir monitoring. The design criteria for a Perforated t 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 1:16- Perforated t
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Completion Design 1.8.5
Sliding Side Door A Sliding Side Door (SSD) or Sliding Sleeve, See Figure 1:17, 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: • • • • • •
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 To assist in the removal of hydrocarbons below packers
NOTE:
As with any 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 are used (e.g. Side Pocket Mandrel, Tubing Perforating).
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Completion Design
Figure 1:17 –Sliding Side Door (SSD)
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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 erosional criteria obtained from fluid velocity and particulate content. NOTE:
1.8.7
In multi-zone completions, Blast ts 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); See Figure 1:18, 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: 1. 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. 2. Chemical Injection Valves -these allow injection of chemicals (e.g. corrosion inhibitors) into the tubing. They are opened by pressure on the annulus side. 3. Circulation Valves -these are used to circulate fluids from the annulus to the tubing without damaging the pocket. 4. 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. 5. 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. 6. Dummy Valves -these are solely isolation devices that prevent communication between the tubing and the annulus. NOTE:
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.
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Figure 1:18–Side Pocket Mandrel (SPM)
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Completion Design 1.8.8
Sub-Surface Safety Valves (SSSVs) The purpose of an SSSV 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. Different operating companies have differing philosophies on the inclusion of an SSSV. For example, in an offshore well, at least one SSSV is placed in every well at a depth, which varies from 200 ft to 2,000 ft below the seabed. The depth at which an SSSV 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 failsafe setting depth). NOTE:
It is generally recommended that an SSSV be installed in a well that is capable of sustaining natural flow. In the North Sea the installation of an SSSV is governed by law.
SSSVs can be divided into type groups according to their method of operation: Direct Controlled Safety Valves These are designed to shut in the well when changes occur in the flowing conditions at the depth of the valve, that is, when the flowing condition exceed a pre-determined rate or when the pressure in the tubing at the depth of the valve falls below a predetermined value. Such valves are often called "storm chokes". These valves are termed Sub-Surface Controlled Sub-Surface Safety Valves (SSCSVs). Remote Controlled Safety Valves These are independent of changes in well conditions and are actuated open usually by hydraulic pressure from surface via a control line 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 safety system, each pilot capable of causing the valve to close if it senses a potentially dangerous situation. These valves are termed Surface Controlled Sub- Surface Safety Valves (SCSSVs). An SCSSVs run on wireline is called a wireline retrievable safety valve (WRSV) and is installed in a special safety valve landing nipple (SVLN) which is made up as part of the completion string; See Figure 1:19. A control line external to the tubing 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 does present a restriction to flow, and can cause hydrate or paraffin plugging if the appropriate conditions exist. An SCSSV run as part of the tubing string is called a tubing retrievable safety valve (TRSV); See Figure 1:20. Again, a control line external to the tubing provides hydraulic pressure to actuate the valve open. The main advantage of a TRSV is that unrestricted flow is provided by its full-bore design, which does not contribute to hydrate or paraffin plugging problems. 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 for the TRSV and the provision for a surface controlled wireline retrievable insert valve to be installed in the body of the TRSV.
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Completion Design
Figure 1:19 –Typical Surface Controlled Wireline Retrievable Safety Valve (WRSV)
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Model “T-5” Safety Valve
Figure 1:20 –Typical Surface Controlled Tubing Retrievable Safety Valve (TRSV)
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Completion Design 1.8.9
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 1:38.
1.8.10 Tubing Hanger The Tubing Hanger is a completion component, which sits 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
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 'annulus Provides an appropriate base for the completion Xmas Tree
Both the Tubing Hanger and Tubing Head Spool are prepared to allow the actuation of an SCSSV. An example of a Tubing Hanger/Tubing Head Spool system is shown in Figure 1:21. Such Tubing Hanger systems allow completion tubing to be suspended in neutral (ie. 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 dosing rams around a hanger nipple. The hanger nipple is run an appropriate distance below a Ram Type Tubing Hanger, See Figure 1:22, 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).
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Figure 1:21 –Tubing Head Spool/Tubing Hanger System
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Figure 1:22 – Ram Type Tubing Hanger System
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Completion Design 1.8.11 Xmas Tree An 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; See Figure 1:23. 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 age 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:
Nowadays, all 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 1:24.
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Figure 1:23 –Typical Xmas Tree
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Figure 1:24 –Typical Surface Wellhead and Xmas Tree
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Completion Design 1.8.12 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 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 1:25. Permanent Production Packers These may run in a variety of ways and become an integral part of the casing once set. A permanent packer may run as follows: •
On 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 tubing pressure.
Figure 1:26 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.
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Figure 1:25 –Example of a Retrievable Packer
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Figure 1:26 – Example of a Permanent Packer
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Latched onto the completion tubing and hydraulically set by the application of tubing pressure.
NOTE:
The tubing may be disconnected from the packer by rotation of the latch system or by utilising an expansion t located in the completion directly above the latch assembly.
Figure 1:27 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:
In general, permanent production packers can withstand much greater differential pressures than the equivalent retrievable packer.
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Figure 1:27 – Example of a Hydro-Set Permanent Packer
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Completion Design 1.8.13 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 1:28 illustrates the assemblies available for connecting the tubing to the packer and maintaining a seal. Locator Seal Assembly Here the top collar or (No-Go Shoulder) locates on the bevel of the packer body, just above the left-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 collar.
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. A completion string may also be spaced out appropriately if overall cooling of the tubing string will occur eg. in a water injection well. Anchor Seal Assembly This seal assembly has a latch sleeve, threaded to match the left-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. 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 1:29.
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Figure 1:28 – Seal Assemblies
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Figure 1:29 – PBR and TSR Schematic Seal Assemblies
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Completion Design 1.8.14 Expansion ts These are telescoping devices, See Figure 1:30, 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 1:30 – Expansion t
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Completion Design 1.8.15 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” 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 1:31.
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Figure 1:31- 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 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 1:4 shows the yield values for various API tubing grades: Grade
H-40 J-55 C-75 L-80 N-80 P105
Minimum Yield (psi) Maximum Yield (psi) Minimum Ultimate Yield (psi)
40,000 55,000 75,000 80,000 80,000 105,000
80,000 80,000 90,000 95,000 110,000 135,000
60,000 75,000 95,000 95,000 100,000 120,000
Table 1:4 -Yield Values for Various API Tubing Grades
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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 break-out when pulling the tubing. Resistance to damage, corrosion, and erosion. There are two types of thread connection -API and .
connections are proprietary connections that offer features not available on API connections. Most offer a metal-to-metal seal for improved high pressure seal integrity. connections exist with features such as flush connections, recess free bores, and special clearance. An example of a thread is shown in Figure 1:32.
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Figure 1:32 - An Example of a Connection
1.8.16 Sub-Sea Wellheads Sub-Sea Wellheads serve the same function as a surface wellhead in providing and pressure integrity but are assembled differently. After positioning a guidebase on the seabed, 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, See Figure 1:33. 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; See Figure 1:34.
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Figure 1:33 – Sub-Sea Wellhead
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Figure 1:34 – Typical Sub-Sea Wellhead and Xmas Tree 1.8.17 Examples of Single String Completions 1. 2. 3. 4. 5. 6.
Single Zone Single String Gravel Pack Completion Single Zone Single String Water Injection Completion Multiple Zone Single String Completion Single Zone Single String Completion c/w ASV System Dual Zone Single String Completion Single Zone Single String Gravel Pack Horizontal Completion
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See Figure 1:35 See Figure 1:36 See Figure 1:37 See Figure 1:38 See Figure 1:39 See Figure 1:40
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Figure 1:35 – Single Zone Single String Gravel Pack Completion
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Figure 1:36– Single Zone Single String Water Injection Completion
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Figure 1:37 – Multiple Zone Single String Completion
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Figure 1:38 – Single Zone Single String Completion c/w ASV System
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Figure 1:39 – Dual Zone Single String Completion
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1.9
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 deg 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, See Figure 1:41, dual tubing hanger systems, See Figure 1:42, and Dual Xmas Trees; See Figure 1:43, 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 ts.
1.9.1
Examples of Dual String Completions 1. Dual Zone Dual String Completion 2. Triple Zone Dual String Completion
See Figure 1:44 See Figure 1:45
Figure 1:40 – Single Zone Single String Gravel Pack Horizontal Completion
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Completion Design 1.9
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 deg 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, See Figure 1:41, dual tubing hanger systems, See Figure 1:42, and Dual Xmas Trees, See Figure 1:43, 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 ts.
1.9.1
Examples of Dual String Completions 1. 2.
Dual Zone Dual String Completion Triple Zone Dual String Completion
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Figure 1:41 – Example of a Retrievable Dual Production Packer
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Figure 1:42 – Segmented Dual Hanger System
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Figure 1:43 – Example of a Dual Xmas Tree
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Figure 1:44 – Dual Zone Dual String Completion
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Figure 1:45 – Triple Zone Dual String Completion
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CONTENTS 1.
COMPLETION DESIGN
1.1
1.1
INTRODUCTION
1
1.2
DESIGN CONSIDERATIONS
1
1.3
COMPLETION AT THE RESERVOIR
5
1.4
PERFORATING 1.4.1 Gun Types and Perforation Methods
8 9
1.5
WELL INFLOW PERFORMANCE
13
1.6
VERTICAL LIFT PERFORMANCE
16
1.7
FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING
19
1.8
COMPLETION COMPONENTS DESCRIPTIONS 1.8.1 Re-Entry Guide 1.8.2 Landing Nipple 1.8.3 Tubing Protection t 1.8.4 Perforated t 1.8.5 Sliding Side Door 1.8.6 Flow Couplings 1.8.7 Side Pocket Mandrels 1.8.8 Sub-Surface Safety Valves (SSSVs) 1.8.9 Annulus Safety Valves (ASVs) 1.8.10 Tubing Hanger 1.8.11 Xmas Tree 1.8.12 Production Packers 1.8.13 Seal Assemblies 1.8.14 Expansion ts 1.8.15 Tubing 1.8.16 Sub-Sea Wellheads 1. 8.17 Examples of Single String Completions
24 24 25 26 26 27 29 29 31 34 34 37 40 45 48 49 52 54
1.9
DUAL COMPLETIONS 1.9.1 Examples of Dual String Completions
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COMPLETION DESIGN
1.1
INTRODUCTION In simple , 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 1:1 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) or 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 13 3/8 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 9 5/8 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: 1. for each casing string. 2. for the BOP equipment for the next section of hole to be drilled. 3. Sealing off the various annuli from pressure control purposes. 4. for the completion string. 5. for the Xmas Tree. 6. 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 1:2 shows a simplified schematic of surface wellhead sections. The letters shown represent a common way of representing annuli. A. The 95/8 ins or production casing string when we insert tubing in the well this would be termed the tubing/production casing annulus. B. The 95/8 ins and 133/8 ins annulus. C. 133/8 ins and 20 ins annulus.
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Figure 1:1- North Sea Casing Profile Example
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Typical OBS drilling sequence
Figure 1:2 – Typical Surface Well Head 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 it reservoir fluids into the borehole at the depth of the reservoir (or reservoirs). 1) Openhole {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; See Figure 1:3a. This type of completion is ideal where the reservoir rock is of the appropriate mechanical strength i.e. is consolidated and 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 costs. Open hole completions offer no scope for isolating individual zones for production, stimulation or remedial work. However, this bottomhole 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. 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 wirewrapped casing (or tubing) which is hung from the production casing and sealed into it; See Figure 1:3b. The slots or wire wrapped pipe prevents sand from entering the wellbore. 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 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 bottomhole completion type has all the disadvantages of the open hole completion with the added cost of the liner and liner hanger thrown in. Its application is 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) Cased and Cemented Completions This is the most common type of bottomhole 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; See Figure 1:3c. 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 1:1.
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Completion Design BOTTOMHOLE ADVANTAGES COMPLETION TECHNIQUE Open Hole No perforating, no production casing, no cementing expense Minimum rig time
Cased and Cemented
Liable to "sand out" No selectivity for production or stimulation
Full diameter hole in the payzone improves productivity
Slotted Liner
DISADVANTAGES
No critical terpretation is required No perforating or cementing expense for the production casing
Ability to isolate is limited to the lower part of the hole No selectivity for production or stimulation
Assists in preventing sand production
Cost of slotted liner or prepacked screen
No critical terpretation is required
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 injection Cost of casing/liner and cementation Cost of rig time for longer completion period
Table 1:1- Bottomhole Completion Techniques -Advantages and Disadvantages
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Figure 1:3 – 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 openhole 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, See Figure 1:4, 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.
Figure 1:4 – Perforation Geometry
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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"; See Figure 1:5a. 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 expands 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; See Figure 1:5b. 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; See Figure 1:5c. 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 (T) (run on tubing)
Figure 1:6 shows schematically the application of the three main perforating techniques. T 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, an Xmas 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. The guns can be jettisoned after firing and allowed to fall to the bottom of the well below the perforated interval. NOTE:
The completion requirement for a T system is to allow an appropriate sump for the guns to fall into.
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Completion Design The advantages of T 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 T 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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Figure 1:5 – Perforating Gun Types
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Figure 1:6 – Perforating Techniques
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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 designed string with tubing as the production conduit. An example of a DST string is illustrated in Figure 1:7. 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. Inflow performance relates to the movement or flow of fluid form 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 are 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 flowrate 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 1:8. 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.
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Figure 1:7 – Typical Drill Stem Test (DST) String
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A (Oil Well) - typical IPR showing Low Productivity. B (Oil Well) - typical IPR showing High Productivity. C (Gas Well) - IPR showing an Additional Pressure Drop caused by inertial and turbulent effects in the vicinity of the wellbore.
Figure 1:8 – Example of an IPR Curve
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Completion Design 1.6
VERTICAL LIFT PERFORMANCE Vertical lift performance (VPR) is concerned with the movement of reservoir fluids from the wellbore at the depth of the reservoir to the production choke on surface. VPR 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 1:9.
Figure 1:9 -Well Outflow and Inflow Systems
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Completion Design NOTE:
During production, critical flowing conditions are usually maintained at the choke
Intake Pressure (psi)
An example of VLP curves for various pipes Ids is shown in Figure 1:10.
Oil Flowrate (bopd)
Figure 1:10 –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; Figure 1:11. 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 1:11 – Matching VLP Curves with an IPR Curve
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Completion Design 1.7
FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING 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 1:1. The objective is to design a completion string for this well with the following basic functional requirements: • • • • • •
To provide optimum flowing conditions To protect the casing from well fluids To contain reservoir pressure in an emergency To enable downhole 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
NOTE:
The above functional requirements are not exhaustive.
A completion string that fulfils these functional requirements is illustrated in Figure 1:12. 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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Swab Valve
Master Valve
Figure 1:12 –Completion Design Example 1
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Completion Design The completion design of Figure 1:12 also addresses the other functional requirements of: • • • • • • • • •
Suspension of 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 1:2. 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 Tubing Hanger Barrier Installation Points Landing Nipples Tubing Hanger Pressure Testing Landing Nipples Pumping Operations Piping Manifold c/w Choke Table 1:2- Component Selection for Completion Example 1
NOTE:
Some components have dual functions.
NOTE:
This completion design utilises a permanent packer and tailpipe that is installed by wireline techniques prior to running the completion string (packer systems will be discussed later).
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Completion Design Completion Design Example 2 Figure 1:13 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 1:3: COMPONENT Tubing hanger
FUNCTION Tubing 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 Wellfluids Ensure Retrievability of All Components Landing Nipple Pressure Testing of Tubing String Barrier Installation Point Installation Point for Plug to Set Packer Perforated t Allows Flow of Fluid when Monitoring Reservoir Performance Landing Nipple (No-Go) Installation Point for Pressure/Temperature Gauges Re-Entry Guide
Allows Unrestricted Re-Entry of Well Intervention Tools Into the Tubing
Table 1:3- 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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Figure 1:13 – 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 1:12 and Figure 1:13. 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: 1. 2.
Bell Guide Mule Shoe
The Bell Guide; Figure 1:14, has a 45° lead in taper to allow easy re-entry into the tubing of well intervention toolstrings (i.e. wireline or coiled tubing). This guide is commonly used in completions where the end of the tubing string does not need to by the top of a liner hanger. The Mule Shoe Guide; Figure 1:14, 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 kick the tubing into the liner.
Wireline Entry Guide with Half Muleshoe Bottom
Wireline Entry Guide with Bell Bottom
Figure 1:14 -Re-entry Guides
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Completion Design 1.8.2
Landing Nipple A Landing Nipple, Figure 1:15 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 bottomhole pressure and temperature gauges
A No-Go Landing Nipple, See Figure 1:15, has a small shoulder located within the internal bore of the nipple for the purpose of preventing 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 No- Go 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 1:15 – 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 t This is a t 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 t A Perforated t, See Figure 1:16, may be incorporated in the completion string for the purpose of providing by flow if bottomhole pressure and temperature gauges are used for reservoir monitoring. The design criteria for a Perforated t 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 1:16- Perforated t
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Completion Design 1.8.5
Sliding Side Door A Sliding Side Door (SSD) or Sliding Sleeve, See Figure 1:17, 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: • • • • • •
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 To assist in the removal of hydrocarbons below packers
NOTE:
As with any 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 are used (e.g. Side Pocket Mandrel, Tubing Perforating).
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Figure 1:17 –Sliding Side Door (SSD)
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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 erosional criteria obtained from fluid velocity and particulate content. NOTE:
1.8.7
In multi-zone completions, Blast ts 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); See Figure 1:18, 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: 1. 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. 2. Chemical Injection Valves -these allow injection of chemicals (e.g. corrosion inhibitors) into the tubing. They are opened by pressure on the annulus side. 3. Circulation Valves -these are used to circulate fluids from the annulus to the tubing without damaging the pocket. 4. 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. 5. 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. 6. Dummy Valves -these are solely isolation devices that prevent communication between the tubing and the annulus. NOTE:
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.
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Figure 1:18–Side Pocket Mandrel (SPM)
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Completion Design 1.8.8
Sub-Surface Safety Valves (SSSVs) The purpose of an SSSV 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. Different operating companies have differing philosophies on the inclusion of an SSSV. For example, in an offshore well, at least one SSSV is placed in every well at a depth, which varies from 200 ft to 2,000 ft below the seabed. The depth at which an SSSV 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 failsafe setting depth). NOTE:
It is generally recommended that an SSSV be installed in a well that is capable of sustaining natural flow. In the North Sea the installation of an SSSV is governed by law.
SSSVs can be divided into type groups according to their method of operation: Direct Controlled Safety Valves These are designed to shut in the well when changes occur in the flowing conditions at the depth of the valve, that is, when the flowing condition exceed a pre-determined rate or when the pressure in the tubing at the depth of the valve falls below a predetermined value. Such valves are often called "storm chokes". These valves are termed Sub-Surface Controlled Sub-Surface Safety Valves (SSCSVs). Remote Controlled Safety Valves These are independent of changes in well conditions and are actuated open usually by hydraulic pressure from surface via a control line 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 safety system, each pilot capable of causing the valve to close if it senses a potentially dangerous situation. These valves are termed Surface Controlled Sub- Surface Safety Valves (SCSSVs). An SCSSVs run on wireline is called a wireline retrievable safety valve (WRSV) and is installed in a special safety valve landing nipple (SVLN) which is made up as part of the completion string; See Figure 1:19. A control line external to the tubing 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 does present a restriction to flow, and can cause hydrate or paraffin plugging if the appropriate conditions exist. An SCSSV run as part of the tubing string is called a tubing retrievable safety valve (TRSV); See Figure 1:20. Again, a control line external to the tubing provides hydraulic pressure to actuate the valve open. The main advantage of a TRSV is that unrestricted flow is provided by its full-bore design, which does not contribute to hydrate or paraffin plugging problems. 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 for the TRSV and the provision for a surface controlled wireline retrievable insert valve to be installed in the body of the TRSV.
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Figure 1:19 –Typical Surface Controlled Wireline Retrievable Safety Valve (WRSV)
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Model “T-5” Safety Valve
Figure 1:20 –Typical Surface Controlled Tubing Retrievable Safety Valve (TRSV)
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Completion Design 1.8.9
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 1:38.
1.8.10 Tubing Hanger The Tubing Hanger is a completion component, which sits 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
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 'annulus Provides an appropriate base for the completion Xmas Tree
Both the Tubing Hanger and Tubing Head Spool are prepared to allow the actuation of an SCSSV. An example of a Tubing Hanger/Tubing Head Spool system is shown in Figure 1:21. Such Tubing Hanger systems allow completion tubing to be suspended in neutral (ie. 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 dosing rams around a hanger nipple. The hanger nipple is run an appropriate distance below a Ram Type Tubing Hanger, See Figure 1:22, 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).
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Figure 1:21 –Tubing Head Spool/Tubing Hanger System
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Figure 1:22 – Ram Type Tubing Hanger System
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Completion Design 1.8.11 Xmas Tree An 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; See Figure 1:23. 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 age 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:
Nowadays, all 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 1:24.
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Figure 1:23 –Typical Xmas Tree
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Figure 1:24 –Typical Surface Wellhead and Xmas Tree
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Completion Design 1.8.12 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 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 1:25. Permanent Production Packers These may run in a variety of ways and become an integral part of the casing once set. A permanent packer may run as follows: •
On 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 tubing pressure.
Figure 1:26 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.
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Figure 1:25 –Example of a Retrievable Packer
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Figure 1:26 – Example of a Permanent Packer
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Completion Design Permanent packers may also be run •
Latched onto the completion tubing and hydraulically set by the application of tubing pressure.
NOTE:
The tubing may be disconnected from the packer by rotation of the latch system or by utilising an expansion t located in the completion directly above the latch assembly.
Figure 1:27 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:
In general, permanent production packers can withstand much greater differential pressures than the equivalent retrievable packer.
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Figure 1:27 – Example of a Hydro-Set Permanent Packer
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Completion Design 1.8.13 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 1:28 illustrates the assemblies available for connecting the tubing to the packer and maintaining a seal. Locator Seal Assembly Here the top collar or (No-Go Shoulder) locates on the bevel of the packer body, just above the left-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 collar.
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. A completion string may also be spaced out appropriately if overall cooling of the tubing string will occur eg. in a water injection well. Anchor Seal Assembly This seal assembly has a latch sleeve, threaded to match the left-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. 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 1:29.
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Figure 1:28 – Seal Assemblies
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Figure 1:29 – PBR and TSR Schematic Seal Assemblies
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Completion Design 1.8.14 Expansion ts These are telescoping devices, See Figure 1:30, 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 1:30 – Expansion t
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Completion Design 1.8.15 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” 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 1:31.
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Figure 1:31- 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 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 1:4 shows the yield values for various API tubing grades: Grade
H-40 J-55 C-75 L-80 N-80 P105
Minimum Yield (psi) Maximum Yield (psi) Minimum Ultimate Yield (psi)
40,000 55,000 75,000 80,000 80,000 105,000
80,000 80,000 90,000 95,000 110,000 135,000
60,000 75,000 95,000 95,000 100,000 120,000
Table 1:4 -Yield Values for Various API Tubing Grades
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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 break-out when pulling the tubing. Resistance to damage, corrosion, and erosion. There are two types of thread connection -API and .
connections are proprietary connections that offer features not available on API connections. Most offer a metal-to-metal seal for improved high pressure seal integrity. connections exist with features such as flush connections, recess free bores, and special clearance. An example of a thread is shown in Figure 1:32.
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Completion Design
Figure 1:32 - An Example of a Connection
1.8.16 Sub-Sea Wellheads Sub-Sea Wellheads serve the same function as a surface wellhead in providing and pressure integrity but are assembled differently. After positioning a guidebase on the seabed, 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, See Figure 1:33. 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; See Figure 1:34.
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Completion Design
Figure 1:33 – Sub-Sea Wellhead
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Completion Design
Figure 1:34 – Typical Sub-Sea Wellhead and Xmas Tree 1.8.17 Examples of Single String Completions 1. 2. 3. 4. 5. 6.
Single Zone Single String Gravel Pack Completion Single Zone Single String Water Injection Completion Multiple Zone Single String Completion Single Zone Single String Completion c/w ASV System Dual Zone Single String Completion Single Zone Single String Gravel Pack Horizontal Completion
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See Figure 1:35 See Figure 1:36 See Figure 1:37 See Figure 1:38 See Figure 1:39 See Figure 1:40
© RGIT Montrose Ltd 2002
Completion Design
Figure 1:35 – Single Zone Single String Gravel Pack Completion
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Completion Design
Figure 1:36– Single Zone Single String Water Injection Completion
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Completion Design
Figure 1:37 – Multiple Zone Single String Completion
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Completion Design
Figure 1:38 – Single Zone Single String Completion c/w ASV System
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Completion Design
Figure 1:39 – Dual Zone Single String Completion
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Completion Design
1.9
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 deg 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, See Figure 1:41, dual tubing hanger systems, See Figure 1:42, and Dual Xmas Trees; See Figure 1:43, 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 ts.
1.9.1
Examples of Dual String Completions 1. Dual Zone Dual String Completion 2. Triple Zone Dual String Completion
See Figure 1:44 See Figure 1:45
Figure 1:40 – Single Zone Single String Gravel Pack Horizontal Completion
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Completion Design 1.9
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 deg 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, See Figure 1:41, dual tubing hanger systems, See Figure 1:42, and Dual Xmas Trees, See Figure 1:43, 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 ts.
1.9.1
Examples of Dual String Completions 1. 2.
Dual Zone Dual String Completion Triple Zone Dual String Completion
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See Figure 1:44 See Figure 1:45
© RGIT Montrose Ltd 2002
Completion Design
Figure 1:41 – Example of a Retrievable Dual Production Packer
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Completion Design
Figure 1:42 – Segmented Dual Hanger System
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Completion Design
Figure 1:43 – Example of a Dual Xmas Tree
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Completion Design
Figure 1:44 – Dual Zone Dual String Completion
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Completion Design
Figure 1:45 – Triple Zone Dual String Completion
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© RGIT Montrose Ltd 2002
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