(e) Downhole pump system
4. COMPLETION STRING COMPONENTS
4.2 Production Tubing
When selecting production tubing, the following data has to be specified:
(a) The grade of steel selected for the manufacture of the tubing, e.g. N80, C75 etc. will be dependent on a number of factors such as the strength requirements for the string and, the possible presence of corrosive components such as CO2 or H2S.
(b) The wall thickness of the tubing referred to as a weight/foot of tubing, has to be specified and this parameter controls the tubing body’s capacity to withstand tensile/compressive stresses and differences between internal and external pressures, e.g. 7" tubing is available as 26, 29, 32 lb/ft. etc.
(c) The threaded coupling is an important part of the design specification as it defines both the tensile strength and the hydraulic integrity of the completion string. The types of couplings available vary from API standard couplings such as Buttress BTC, Extreme Line EL, Long Threaded Coupling LTC, etc.to the specialised or premium threads commonly selected for production tubing such as Hydril, VAM, etc. These latter proprietary designs offer specific advan tages, e.g. VAM was developed for completing high pressure gas wells, where rigorous sealing and pressure integrity is difficult to achieve but essential.
4.3 Provision of an Annular Pressure Seal
In the previous discussion of completion types it was suggested that the provision of an annular seal or pack-off in production wells was necessary for one of the following reasons:
(a) To improve flow stability and production control
(b) Protection of the outer containment system/equipment such as the production casing and the wellhead.
(c) To provide the facility to select or isolate various zones during stimulation or production, e.g. to isolate two producing zones having different fluid properties, GOR, pressure or permeability (especially relevant for injection) or to stimulate or pressure maintenance.
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Wellbore Completion Concepts
Left - Hand Screw Head Inner Mandrel Friction Blocks Upper Seal Sealing Element Bypass Upper Cone Lower Cone
Upper Split Nut Lower Split Nut Slips
The most common method to provide an annular seal is the use of a packer. There are numerous manufacturers, each offering a variety of designs; however, Figure 9 illustrates a basic packer. The pack-off is accomplished by expanding or extending the elastomer element outwards from the packer body until it contacts the casing wall. There are four main characteristics which classify the various packer types:
(a) Retrievability
Here, the consideration is how easy is it to release the packer after setting. This aspect is of importance since it not only affects the degree of difficulty in working over a well, it may also reduce the applicability by introducing design limitations in terms of the differential pressure it can withstand. However, in general terms, the following categories are available:
(1) Retrievable Packer which, as its name implies, can be easily retrieved after installation. The packer can be run as an integral part of the tubing string to the setting depth where the setting mechanism is actuated.
Figure 9
Major Components of a Typical Production Packer
1
(2) Permanent Packer which, as its name indicates, cannot be easily retrieved. It is usually run and set separately with or without the tailpipe, and the tubing string is subsequently run and engages the packer to achieve a pressure seal within the central bore of the packer. To retrieve the packer it is necessary to mill away the packer internal sleeves to allow the rubber element to collapse.
(b) Setting Mechanism
The setting of packers can be accomplished by a number of mechanisms, all of which cause compression and extrusion of the rubber element:
(1) Mechanically - one example of such mechanisms is rotation of the tubing string.
(2) Compression or Tension (based on suspended tubing weight). Normally, some mechanical device is required which when activated at the setting depth allows for example, string weight to be transferred to the packer to compress the rubber element. See Figure 10. These packers are simple but often unidirectional in terms of the setting force and ability to withstand a differential pressure
Sealing Elements Lower Cone
Lower Slips
(3) Hydraulic - this mechanism utilises hydraulic pressure generated inside the completion string. By necessity, the tubing string is isolated or plugged below the packer to prevent pressure being exerted on the formation or the annulus during setting.
(4) Electrical - with this mechanism a special adaptor and setting tool is connected to the packer which allows the packer (plus tailpipe) assembly to be lowered into the casing on electrical conductor cable and at the required setting depth a small explosive charge can be detonated, thus actuating the setting mechanism.
(c) Ability to Withstand Differential Pressure
(1) Compression Packers (e.g. weight set) In the case of normal producing wells, higher pressure below the packer compared to above counteracts the setting mechanism. This type of packer is thus suitable for injection wells where the differential pressure supports the setting mechanism.
Figure 10 Schematic of a
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Wellbore Completion Concepts
(2) Tension Packer This is the opposite to the compression packer and hence a higher pressure below compared to above (as in production wells) supports the setting mechanisms.
(3) Compression and Tension Set Packers These packers can withstand pressure from either direction.
(d) Packer Bore
As indicated above, it is necessary to have a bore through the packer for each tubing string. Single, dual or triple bore packers are available for multiple tubing string completions (refer to Ch. 7).