Equipment, sealing for HP/HT completions.

Recently there has been much interest and discussion of completion equipment and methods of completion for some wells in the North Sea and other areas which are being termed high pressure/high temperature (HP/HT). In reviewing information from several sources, HP/HT wells could be classified as being above 177[degrees]C and 83 MPa and for the purposes of this article, we will adopt this pressure/temperature definition as well. Although there seems to be no typical HP/HT chemical environment, in various oil company tender documents references are made to "gas with associated condensate" or "retrograde condensate and volatile oil" with up to 10% CO2, trace amounts of H2S, and completion fluids ranging from inhibited seawater to special HP/HT polymer or synthetic oil muds. Completion schemes will include both under balanced and over balanced perforation with subsequent run in of PBR, or tubing to packer, seals and then flow testing and production. Although these wells have only more recently become of interest in the North Sea area, well completions in environments similar to these HP/HT environments have been undertaken in South Texas for several years. Actually, many of the wells in South Texas are well above the HP/HT temperature minimum with temperatures reaching into the 21 8C to 232[degrees]C range and pressures in the 69 MPa to 83 MPa range. The South Texas wells are typically gas wells with some condensate production and usually less than 1% H2S content. With the history of completions in these well environments, we have a good basis on which to look forward to completions and expected performance in the North Sea and other HP/HT wells.

Permanent packers designed for the HP/HT well environment have already demonstrated good performance, not only in South Texas and other areas in the U.S., but have been used with the same good performance in production tests completed in the North Sea area. Most of the HP/HT work conducted so far in the North Sea area has been relatively short term production testing and the PBR seals have for the most part been held static. Due to design differences between the PBR seals and the packing element, some different aspects of performance need to be evaluated.

Equipment and completion design

There are actually two basic types of packers, permanent and retrievable, which are used in various completion situations. In each of these basic types there are many variations in design. Traditionally, there has been a fairly clear dividing line in performance of permanent and retrievable packers with the temperature/pressure dividing line at about 149C and 69 MPa. Permanent packers were used above this level and retrievables below. Retrievability at temperatures and pressures above this level has not proven reliable and leak free pressure containment is very questionable. This selection criteria and performance difference is no longer so clear cut.

The primary difference in these two types of packers is indicated by their name. A permanent packer is just that. Once set in place in the casing bore, the packer cannot be removed unless the locking mechanism is milled away to release the applied setting load from the locking system and packing element. A retrievable packer has a locking mechanism which can be released, retracted, and allows the setting force to be removed from the elastomeric packing element and support system. The packer may then be pulled from the well with the tubing, hence eliminating costly milling operations and rig time.

Some sizes of permanent packers have been designed and tested to withstand mechanical loads at a pressure of 117 MPa and temperature of 232[degrees]C for use in the particularly high pressure environments. A permanent packer is a device that, using a non-removable slip arrangement, is locked into position in the casing and is able to withstand considerable mechanical loads. The seal between the packer body and casing inner diameter, referred to as the packing element, is a critical determinant of performance. Proper design is required to create a 100% mechanical support of the elastomeric sealing material thus allowing the packing element to remain intact to very high pressure differentials (figure 1).

More recently, a fully retrievable packer (figure 2) has been designed and performance demonstrated with the capability of 103 MPa at 232[degrees]C. Use of previous high pressure retrievable packers with capabilities near these limits always left a question of retrievability after a short period of service. The retrieval mechanisms did not always function sufficiently to release the tool and the packing element back up system did not retract from the casing wall. They often have to be milled out of the well just as a permanent packer. The current packer has been designed to accommodate setting forces without binding the setting mechanism and mechanically retracts the packing element back up system so full retrievability is attained.

In either application, judicious selection of not only the proper type of polymer, but evaluation of mechanical properties and chemical stability of the packing element compound is paramount to a packer's performance. Testing of the packing element systems must take into account the material's properties, not only in the high pressure/high temperature condition, but the material properties present when the packer is set in the casing, which may well occur at a much different temperature than the long term application temperature. In addition, consideration must be given to what might occur at the packer if substantial temperature changes might take place during its service life. Polymer materials are available with adequate chemical stability to the more common completion fluids, but chemical stability in the newer polymer based and synthetic oil based HP/HT completion fluids has not been as well defined. Evaluations of sealing materials in the polymer based and synthetic oil based fluids should be instituted before long term completions are undertaken. It may be necessary to utilize hybrid or composite element systems to achieve the desired combination of chemical and thermal resistance with the required mechanical strength. The packing element system developed for the HP/HT packer utilizes both Aflas and Teflon materials to insure proper performance.

In current HP/HT applications, either of these types of packers would be connected to the tubing string by some type of seal assembly sealing in the ID bore of the packer or seal bore located just above the packer. These seal bores are sometimes referred to as polished bore receptacles or PBRs.

PBR seal units (figure 3) have been tested statically for these very high pressure, 117 MPa, applications and dynamically at pressures up to 103 MPa. For the purposes of this article, reference to PBR seals incorporates seal designs for both static and dynamic sealing from tubing directly to a casing (polished) bore receptacle or other polished bore receptacle whether that receptacle is part of the packer or designed as an accessory. These seal units typically consist of an elastomeric v-ring with associated thermoplastic back up rings which add mechanical support to the elastomeric seal much in the same manner as the permanent packer (figure 4). Again, the selection of the appropriate elastomeric seal and thermoplastic back up material for adequate chemical stability and mechanical strength is paramount to good completion performance. Based on South Texas area field performance even in the more typical completion fluids, however, there has been one aspect of PBR seal performance which requires review with intent not only toward improvement, but to definition of performance criteria as well.

One common type of completion design has seal assemblies which seal from the tubing to a polished bore whether that bore is an integral part of the casing, packer or other item of equipment. Some of these completion designs allow these seal units to remain static in the seal bore and others allow the seals to move in a reciprocating type motion. There are many different thoughts on how completions should be designed and which specific method of sealing should be employed, but this detail is beyond the scope of this article. Let us take the case in which a packer and tubing to packer seal assemblies are used. With this type of hook up, the seal units could be set up to be static - anchored into place - or allowed to float, which causes them take on a dynamic aspect. Static applications of tubing seals are the optimum. Elastomeric tubing seal units which are held static can be designed to hold very high differential pressure and high temperature. As mentioned, packers and static tubing seal units have been tested for HP/HT use at a pressure of 117 MPa at 232[degrees]C. The static application is also an area where non-elastomeric or metal to metal type seals have been developed with good performance characteristics. However, it is the dynamic aspect of current elastomeric tubing seal designs which is open for discussion.

Tubing seal applications

When the seal units attached to the tubing are anchored into the packer, very high mechanical loads can be transmitted into the packer and casing due to expansion/contraction of the tubing string. Although being held static is considered optimum for the seal unit, in some completion design theory the high loading into the packer is not desirable. In those cases, completions must be designed to allow movement of the tubing in response to temperature and pressure changes in the well bore. Completions which allow the tubing to move must have seals which are capable of being inserted into the polished bore, sustaining both low and high pressure differentials, and retaining a sealing stress imposed initially by designed interference with the seal bore and later by applied pressure differential. This imposed dynamic performance of PBR seal units has traditionally been evaluated in the engineering laboratory by mechanically inserting or stabbing in a seal unit into a seal bore while at test temperature being careful to not generate a high differential pressure, and applying the required differential pressure after stab in. If a seal unit cannot be inserted into the seal bore while hot without sustaining mechanical damage, the probability of having seal leakage is very high. The seal unit is then mechanically moved in the seal bore while under a differential pressure as if the tubing length were changing, but it is almost impossible to maintain the full pressure differential and at the same time monitor leakage across the seal unit due to the changing volumes above and below the seal unit (figure 5). Length of travel is limited to a few feet in each direction in the typical set up. In this type test, the pressure is reestablished at the end of each stroke on the opposite side from the initial pressure application, and held for a short period of time to determine whether leakage across the seal unit is occurring. This test method, then, evaluates a seal unit's performance, including stab in capability, while hot and with reversing pressure differentials in what I have termed a semi-dynamic mode of movement. Although by this test method or ones similar, PBR seals have been tested up to 232[degrees]C and 103 MPa without leakage, field performance in South Texas HP/HT well conditions has raised a question of evaluation by this semi-dynamic test method versus a continuous dynamic test method.

The continuous dynamic test method utilizes dual seal units which face each other on the seal mandrel (figure 6). Seals are heated, after insertion by hand into the test fixture, and pressure is applied between the seal units which allows monitoring of pressure in a constant volume. The mandrel two inch stroke. In this test method, pressure differentials cannot be reversed as you would then have the same problem of maintaining and monitoring the pressures with changing volumes encountered in the semi-dynamic method. Tests have been conducted in this continuous dynamic mode with up to one mile of travel, pressure at 69 MPa and temperature at 232[degrees]C. In these conditions, seal wear becomes another factor for consideration. One main difference seen in the results of the two types of evaluation procedures (table 1) is that a 100% leak free seal has not been observed in any continuously dynamic test, hence comes a question of test procedure, test criteria and what is actually required for downhole service. While I am sure that many would agree that we should strive toward developing a 100% leak free continuously dynamic sealing capability, is that what is needed?

Table 1 - test procedure comparison
Dynamic test results
Test type        Test Conditions        Test results
Semi-dynamic   Semi-dynamic movement         No leaks after pressure
               Repressure at end of stroke   reestablished at end of
               Up to 232[degrees]C           stroke
               Up to 103.5 MPa
               Travel up to 24.4 m
Continuous     Continual short stroke        Small leak rate seen on
dynamic        Pressure maintained between   tests of .7 KPa/m to
                 seal units                  5.5 KPa/m
               Up to 232[degrees]C
               Up to 69 MPa
               Travel up to 1,609 m

Summary

Two types of completion equipment have been described - packers and tubing to polished bore receptacle seal assemblies. Two types of packers have been discussed - one of which is a newly developed HP/ HT retrievable packer. The new HP/HT retrievable packer is capable of service at 232C and 103 MPa. Its use will allow additional diversity in future completion designs over what was achievable with only permanent packers. The Tubing to PBR application was described and designs, materials and test procedures were reviewed.

In consideration of the tubing to PBR application, is a 100% continuously dynamic seal required? While we do not acknowledge that a leak free continuously dynamic sealing capability is not achievable, it very probably will require an all out design effort to achieve that level of sealing capability especially when stab in is also considered. Leakage rates in the continuous dynamic mode are measured in a few tenths to as much as 3.36 kPa per meter of travel in tests run for approximately three weeks to achieve 1,609 m of travel. That length of travel was a requirement for a specific application. Obviously, that equates to about 13.8 MPa - 54 MPa drop in pressure in three weeks which is far more than has been seen in actual HP/HT downhole applications - even applications similar to those for which the continuous dynamic test procedure was developed. 1,609 m of travel while in a seal bore, if seals ever have to move that far, would likely require time periods of 15 to 20 years rather than three weeks. Is it realistic to accelerate the travel in this manner? Both static and semi-dynamic evaluation procedures have demonstrated a no leak capability. Many static and dynamic downhole sealing applications have shown that to be the case, while in other applications we have seen some leakage indicated by pressure build up in the annulus. There should be a reasonable test procedure somewhere between the two procedures described which will more clearly define sealing performance in actual application. In addition, part of the quest to design an improved continuous dynamic sealing capability is to first define not only the appropriate test procedure, but the criteria for evaluation and acceptance of seal performance.

Figure 1 [ILLUSTRATION OMITTED]

References

[1.] Abrams, P.I., Johnson, D.V. and Kennelley, K.J. "A user's approach to qualification of dynamic seals for sour-gas environments," Rubber Division of American Chemical Society, Cincinnati, Ohio, October, 1988. [2.] Rubbo, Richard P., "What to consider when designing downhole seals," World Oil, June, 1987. [3.] Fennel, R., Avignon, B., Henderson, D., "Qualification of an HP/HT retrievable production packer," Society of Petroleum Engineers, London, England, SPE Paper No.