Cased hole completions

Matching the correct equipment to the application is critical to the success of the completion. The equipment must meet or exceed the temperature, pressure, and axial-load conditions created by the various operating modes anticipated over the life of the well, and material selection should match the well environment. Most of all, the completion design should be fit for purpose and meet the production objectives in an efficient and cost-effective manner.

Single string LP/LT wells

Single-string low-pressure (less than 3,000 psi) flowing or injection wells completed at relatively shallow depths (less than 3,000 ft) generally use a retrievable tension packer (Fig. 1). This is largely out of necessity, because the tubing weight is not sufficient

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  Fig. 1—LP/LT completion.

A wireline entry guide below the packer, but above the perforations, should be used to facilitate any through-tubing operations that are planned. It is advisable, but not mandatory, to run a profile seating nipple either above or below the packer. The addition of the seating nipple allows a blanking plug to be run to test tubing if a leak occurs, and the nipple will act as a stop should tools be lost in the hole.

Single-string medium-pressure/medium-temperature wells

In median pressure and temperature applications, a retrievable compression/tension set versatile landing-condition packer may be used. In these applications, pressures typically will range from 3,000 to 10,000 psi, and bottomhole temperatures (BHTs) may be anywhere between 100 and 300°F (Fig. 2). These types of tools are generally suited for the higher pressures and temperatures that will be encountered because of the more sophisticated packing-element systems they have. Also, in deeper installations, the addition of a bypass system aids in equalizing the tubing and annular fluids to facilitate retrieval of the packer. In these applications, the longer tubing length presents a different challenge from that in the shallow applications, in which a tension packer would have been used. In flowing wells, the tubing will heat up and elongate and add weight to the packer if landed with compression on the packer, or it will lose tension if landed in tension. In injection wells, the opposite will be true. Careful consideration should be given to these conditions and to future planned pumping or stimulation operations and their effects on tubing movement when making a packer selection.

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  Fig. 2—Single-string medium-pressure/medium-temperature completion.

As for most wells equipped with packers, a wireline entry guide on the bottom of the packer will aid in guiding electric-line and coiled-tubing tools back into the tubing string when performing through-tubing operations. A profile seating nipple is run below the packer to facilitate the running of bottomhole-pressure recorders or to allow a blanking plug to be installed for temporary well control. A second profile seating nipple may be run above the packer to test and verify tubing integrity or to land a bottomhole choke. The addition of a sliding sleeve or gas-lift mandrel with a dummy to the tubing string allows the tubing to be displaced with lighter fluid to bring the well in or circulate kill-weight fluid into the tubing string during subsequent workover operations while the wellhead is flanged up.

Single-string high pressure/high temperature (HP/HT) wells

In HP/HT applications, where the pressure can exceed 10,000 psi and temperatures are above 300°F, a permanent sealbore packer is generally used (Fig. 3). However, there are some specialized retrievable packers that can work in these applications under limited conditions.

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  Fig. 3—Single-zone permanent packer completion using locator type seal assembly.

The permanent sealbore packers are very versatile and are designed to accommodate the extreme tubing movement and high axial packer-to-tubing forces encountered in HP/HT completions. Tubing-movement calculations should be performed to determine the length changes and stresses on the tubing string in the production, shut-in and treating, or injection modes. Depending on the length changes and stress created on the tubing, a permanent packer with a located (floating) or fixed (anchored) seal assembly may be required.

As before, a wireline-entry guide on the bottom of the packer will aid in guiding electric-line and coiled-tubing tools back into the tubing string when performing through-tubing operations. One, and in some instances two, profile seating nipples are run in the tailpipe below the sealbore packer for landing bottomhole-pressure recorders and facilitating well control during completion and workover operations. The seal assembly may be anchored into the packer or a locator type with additional seal length to accommodate tubing movement. A profile seating nipple is run above the seal assembly for tubing-test purposes or for landing a bottomhole choke.

Multiple-zone single-string selective completion

Multizone single-string completions with median temperatures and differential pressures will likely use hydraulic-set single-string retrievable packers (Fig. 4). This style of completion allows all the available zones in the well to be completed at once and produced individually or commingled. Sliding sleeves are positioned between each isolation packer. There is no limit to the number of packers and sliding sleeves that may be run, but each addition should be justified. When one zone depletes, the workover is accomplished with slickline by landing a blanking plug in the lowermost profile nipple or opening and closing one or more of the sliding sleeves. It should be noted that complex completion designs with multiple packers and accessories cost more and often increase major workover costs significantly. The designer should have a feasible plan for pulling the well’s tubing string(s).

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  Fig. 4—Multiple-zone single-string selective completion.

The hydraulic-set retrievable packers can be run in on one trip and set simultaneously by applying pressure to the tubing against a plug set below the lowermost packer. After setting the packers, the plug may be retrieved and the lowermost zone may be produced or, alternately, one of the sliding sleeves may be opened to produce one of the corresponding upper zones.

A profile seating nipple is run below the lowermost packer to accept a blanking plug (or check valve) to set the hydraulic-set packers and to provide well control for the lower zone. Sliding sleeves are positioned between each packer for zonal isolation. Blast joints should be positioned across the perforations between the isolation packers to reduce the risk of erosion damage to the tubing string from well fluids and produced sand. A sliding sleeve or gas-lift mandrel with dummy may be positioned above the uppermost hydraulic-set packer to aid in circulating kill fluid in the hole or circulating lighter fluid or gas in the tubing to bring the well on production.

Dual-zone completion using parallel tubing strings

The dual-zone completion method generally is used in applications in which it is desirable to produce two zones simultaneously while keeping them isolated from each other (Fig. 5). In this completion, two strings of tubing are run from the surface to the dual packer. One string terminates at the dual packer, and the other string of tubing extends from the dual packer to the lower single-string packer. The tubing string that produces the upper zone is referred to as the “short string” (or upper tubing), and the tubing string that produces the lower zone is called the “long string” (or lower tubing).

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  Fig. 5—Parallel-string dual-zone completion.

In cases in which the zones are of equal pressure and crossflow is not an issue during the completion stage, a single-string hydraulic-set packer may be used as the lower packer. This allows the entire completion to be run in a single trip and both packers to be set after the wellhead is flanged up.

In parallel string completions in which the zones are subject to crossflow because of unequal pressures, the lowermost single-string packer is generally a sealbore packer. The sealbore packer is set with a temporary plug in place for well control before perforating and running the upper completion. The plug keeps the two zones separated until the upper completion is installed and the wellhead is flanged up.

The upper packer in this example is a hydraulic-set dual-string retrievable packer. Models exist that can be set by applying pressure to the long string, but the more common models require the short string to be pressurized to accomplish packer setting. The decision about which type depends on the various operations that are planned.

A profile seating nipple is run below the lowermost packer and below the dual packer on the short string to accept a blanking plug (or check valve) to set the packer and to provide well control. A sliding sleeve is positioned between the packers for aid in circulating kill-weight fluid in the hole or circulating lighter fluid or gas in the tubing strings to bring the well on production. A blast joint should be positioned across the perforations of the zone between the packers to reduce the risk of erosion damage to the long string from well fluids and produced sand. Profile seating nipples should be run above the dual packer on both strings for well control or testing tubing for well-diagnostic purposes.

Bigbore or monobore completions

In highly prolific reservoirs, tubing of 6 5/8 in. and larger diameters is required to meet cost-effective production and injection objectives. The use of big monobore-completion techniques can increase production rates significantly while decreasing both capital and operating expenses. The advantages of the big monobore completion systems include the elimination of gas-turbulence areas and restrictions on production while providing access for well-intervention purposes. This can translate to fewer wells required for optimized reservoir production, resulting in a faster return on initial investments and lower long-term operating expense.

Big monobore completions are basically liner-top completion systems. The key is the large inside diameter (ID) tubing that allows increased production rates and provides full-bore access to the production liner. Full-bore access gives the operator the ability to run conventional tools through the tubing to perform remedial work in the production liner without disturbing the completion or pulling the production tubing. There are many styles of monobore completions from which to choose. The selection of the type system that is used depends largely on the pressure integrity, and the pressure capability, of the liner top and intermediate casing string.

In the most basic monobore-completion design (Fig. 6), the production liner is run and cemented in the hole. At the top of the liner hanger is a polished bore receptacle (PBR) to accept a seal assembly. The production tubing that is used has basically the same ID as the liner. When the completion is run, a seal assembly is run on the bottom of the production tubing and landed in the PBR. The seal assembly and liner top provide the annular barrier for the tubing string. The constraints of this system are:

• The ID of the polished bore receptacle can become damaged during liner cleanout trips and fail to seal
• The ability of the liner top to hold pressure is totally dependent on the quality of the cement job.

Remedial work to the liner may be required before running the completion.

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  Fig. 6—Basic monobore liner-top completion.

A more reliable monobore system (Fig. 7) will use a packer above the liner top. In this system, the liner is run and cemented as before. When the completion is run, a large-bore hydraulic-set permanent packer is installed. The packer will have a PBR located above it, with the tubing seals run in place. There is also a seal assembly on the tailpipe below the packer, which is stabbed into the liner top. The packer provides a more positive annular barrier, and a new PBR has been installed.

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  Fig. 7—Monobore completion with liner-top isolation packers.

See also

PEH:Completion_Systems