Well Design And Equipment Installation For Mobile Bay Completions
Authors: Gordon J.R. , Johnson D.V. , Herman S.R. , Darby J.B. 
Published: October 2008

Production of sour gas from deep (21000-foot) reservoirs extended offshore in recent years and has challenged operators to assure equipment integrity and reliability. The high investment in wells and facilities, as well as the high cost of remedial wellbore activities, make quality of initial installations a high priority. This paper emphasizes key design and installation topics for a recent eleven-well development in the Mobile Bay area. Over 50 staff-years of R&D effort were expended in establishing suitability of equipment and procedures for the development. Focus of the paper is on sharing results of key elements in a process covering more than a decade which were critical in effecting successful and optimum deep sour gas completions.

OVERVIEW

As shown on the area map, Figure 1, the eleven wells are in three separate fields. Separation and dehydration facilities are located at each field and gas is gathered at these facilities via corrosion resistant alloy (CRA) flowlines. Commingled gas and commingled liquids are transported to an onshore treating plant in separate steel pipelines1.

Produced fluids are from the Norphlet sandstone formation and contain between 50 ppm and 10% hydrogen sulfide together with 3.5% carbon dioxide. Surface conditions are 8000-10600 psi shut-in pressure and 290-320F flowing wellhead temperature.

The wells were drilled between 1983 and 1992 and left temporarily abandoned. Completion activities were carried out from June 1992 to May 1993, with startup of the wells during fourth quarter 1993.

WELL DESIGN PHILOSOPHY

From the outset of well planning in 1982, longevity and simplicity were the criteria which every wellbore component had to satisfy. The well design would have to tolerate extremely corrosive and erosive well conditions (acid gases, 420F bottomhole temperature, and 50 MCFD flow rates). Equipping the wells for chemical injection to control corrosion and/or solids deposition represented a severe wellbore complication requiring unproven downhole hardware.

With the above criteria, the final well design, Figure 2, featured a full CRA flow path and a single mechanical device, the subsurface safety valve (SSSV). The SSSV was a shallow restriction in the wellbore (2.56" ID) which posed no real operational constraint. Floating seals inside a polished bore receptacle (PBR) eliminated packers and latches and the attendant risk and difficulty of removal during workover operations. The CRA flow path eliminated the need for downhole chemical injection hardware. Batch treatment for removal of deposited solids had also been demonstrated at several locations around the world.

In addition to providing the needed corrosion protection for a long-life completion, the choice of CRA for the production tubing also permitted increased flow rates to take advantage of the lower susceptibility of CRA material to erosion.

Four early exploration wells with steel production casing at total depth (TD) were retrofit with 4-½" CRA liners; this provided comparable longevity to the later drill wells where the bottom of the production casing was CRA, These CRA liners presented special installation and perforating challenges which will be discussed later.