Considerations for Pressure Control Equipment for HighTemperature, High-Pressure (15 ksi) Subsea Completion Systems

Abstract

INTRODUCTION Numerous subsea exploration wells have been drilled with shut-in pressures in excess of 10,000 psi, and many of these wells were also classed as high temperature. These types of wells are generically termed High pressure, High Iemperature or HPHT. Although the exact definition for HPHT wells varies, both high temperature and high pressure [1, 2] must be present for this designation. Work done to date has been more concerned with the higher pressures, since a significant number of these discovery wells, many of which are located in the Central Graben region of the North Sea, await development. Undoubtedly many of these wells will use Subsea Production Equipment (SSPE) as such systems are now commonplace in providing cost effective developments within the established infrastructure of the North Sea. However, equipment does not as yet exist for pressures greater than 10,000 psi, hence a need to develop SSPE for HPHT wells. This paper describes a systemized approach to the designof such equipment as it is very much governed by the required design specifications and by the equipment interfaces. Since development costs will be high, it would be advantageous to avoid a proliferation of different designs, sizes, and centers and it is hoped that this rationale willprovide a uniform platform to assist in the future design and standardization of these systems. GENERAL FEASIBILITY Most SSPE systems are rated at 5,000 psi; however, in recent years, some have been manufactured with 10,000 psi rating. The development of a 15,000 psi rated systemwill rely heavily on these previous systems, drawing upon the experience already gained, and making modifications where necessary. Many components within the system are not directly affected by well bore pressures and temperatures and can thus remain the same. Feasibility studies have been performed recently and in most areas, the overall feasibility was never in doubt. The only question was what the preferred design would be, particularly where there was no definitive and restrictive size "envelope" to work within. In other cases where there were restrictions, such as inside the wellhead, the dimensional constraints had to be carefully evaluated. In order to make these systems economical, and as standard as possible, an adequate sized production tubing willneed to be provided for. This will be in combination with a means to isolate the annulus in the tubing hanger. The studies performed to date have considered parallel bore systems with vertical access into both production and annulus tubing hanger bores to set and retrieve wireline plugs. The maximum bore sizes are very much dependant on casing size, annulus tubing requirement, material yield strength and tubing coupling size. Previous studies have shown that a nominal 4" × 2" system is feasible with a10-314" production casing and annulus tubing. The same bore sizes are also feasible with a 7-5/8" production casing but with no annulus tubing. Obviously the production casing size is dependant on the well's overall casing program, butfrom experience, most HPHT wells will utilize a 7-5/8" or smaller production casing string [1].