Elastomers are rubber or plastic materials used as a seal. They are commonly used in packers. There are many suitable elastomers on today's market to match almost any downhole condition. Care must be taken to ensure that the elastomer selected for the packer and seal assembly meets all the downhole conditions to which it will be subjected. There is no single best elastomer that will perform under all conditions combined, and selection must be tailored to suit individual well requirements and application.

Profile seating nipples and sliding sleeves have a special locking groove and a honed sealbore to allow a flow-control device to lock in the nipple and seal off when installed. By design, the sleeves and nipples will have a smaller inside diameter (ID) than that of the tubing string. For this reason, careful consideration must be given to the overall application and completion design when selecting and sizing the various models of profile seating nipples and sleeves. This is especially true in any case in which through-tubing operations or perforating are planned. Correct application of flow-control accessories can greatly reduce the time and money spent on diagnosing well problems (such as tubing or leaks) should they occur.

The tubing and packer selections in combination completions must consider the impact of the multiple fluids, tubing, or casing. Hammerlindl[1] presented a method for solving problems with combination completions. His paper in particular covered two items not previously addressed by Lubinski et al.[2] He includes a direct mathematical method for calculating forces in uniform completions in which tubing movement is not permitted and a method of handling hydraulic packers is set with the wellhead in place. There are several computer programs available today, modeled after Hammerlindl's methods, that can easily calculate the length changes and forces generated by changes in temperature and pressure within the wellbore. These programs not only determine critical length changes but also the stresses generated on the tubing string and packer.

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.[1] 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 (Figure 1). A wireline entry guide below the packer, but above the perforations, should be used to facilitate any through-tubing operations that are planned.

A downhole log recording, given by magnetic deflection, of the location of couplings or other equipment.

To evaluate a given casing design, a set of loads is necessary. Casing loads result from running the casing, cementing the casing, subsequent drilling operations, production and well workover operations. External pressure loads are produced by cement and fluids outside the casing, which can be modeled by pressure distributions. Pressure distributions are typically used to model the external pressures in cemented intervals. These pressure distributions are discussed next.

A settled plug made of particles or barite or even barite and sand that are placed to seal off a zone or the wellbore.

Mechanical device activated by pumping a ball of a certain size down the tubing in the injected or circulated fluid.

A cylinder at surface to catch ball sealers before the fluid is routed through the choke.

A cement plug, set with no downhole flow conditions, which allows temporary or permanent shut-off in a well. It takes into account the densities of all fluid columns, both in the string and in the annulus.