A Completion Design for High-Capacity Offshore Gas Wells
Authors: Hartley R. 
Published: December 2007

Sarawak Shell Bhd. (SSB) is currently developing two offshore gas fields to supply about 1,200 MMscf/D (34.3 × 10(6) std m3/d) to a liquid natural gas (LNG) plant being built at Bintulu, Sarawak. Both fields are plant being built at Bintulu, Sarawak. Both fields are carbonate buildups with very high productivities but, because of their relatively shallow depth, only moderate reservoir pressure. The produced gas is lean, With CO2 content of up to 7.3% and H2S content of about 8 ppm. Because the wells are offshore, there is increased risk caused by the proximity of other wells and the possibility of platform damage. Being offshore also means high costs for drilling, compression, and workover. This paper discusses the completion design developed to cope with these conditions. Safety considerations, the prevention of corrosion, and tubing stress analysis are prevention of corrosion, and tubing stress analysis are discussed. The final design uses 7-in. (17.8-cm) tubulars, including 13% Cr steel at points where corrosion may be severe, and uses a fire-resistant Christmas tree and wellhead design.

Introduction

As operator for the Malaysian national oil company, Petronas, SSB currently is developing two offshore gas Petronas, SSB currently is developing two offshore gas fields in the Central Luconia province of Sarawak to supply about 1,200 MMscf/D (34.3 × 10(6) std m3/d) to an LNG plant at Bintulu. Development drilling started in the El I field in May 198 1. Drilling in the second field, F23, should begin in Dec. 1982. Ten to twelve wells are planned initially for each field with the possibility that planned initially for each field with the possibility that four additional wells could be required in E11 field at a later stage. The development of a third field, F6, depends on the production performance of E11 and F23 and the increase in market demand. Both E11 and F23 ar-e carbonate buildups with very high productivities. Planned deviations for development wells require Planned deviations for development wells require kickoff between 500 and 2,000 ft (152 and 610 m) subsea, 2 1/2 degrees/100 ft (0.00143 rad/m) buildup to a maximum of 45 degrees (0.785 rad), and a tangent section to total depth. The casing scheme selected for E11 and F23 wells comprises a 9 5/8-in. (24.4-cm) production string and a 7-in. (17.8-cm) liner across the productive zone. This paper describes the completion design developed for the two fields.

The Fields

Ell field is a pinnacle-type carbonate buildup, and gas will be produced from the interval of 4,740 to 6,477 ft (1445 to 1974 m) subsea. Reservoir pressure is 2,885 psia (19.9 MPa) at 6,000 ft (1829 m) subsea, and psia (19.9 MPa) at 6,000 ft (1829 m) subsea, and pressure at top carbonate is equivalent to a 0.59 psi/ft pressure at top carbonate is equivalent to a 0.59 psi/ft (13.35-kPa/m) gradient. CO2 content of the gas is 7.3% and the H2S content is 7 ppm, giving partial pressures of 211 and 0.02 psia (1.45 MPa and 0. 14 kPa), respectively. The calculated maximum production rate from the top zone at initial conditions is more than 200 MMscf/D (5.7 × 106 std m3/d) per well. Other technical considerations limit the planned production rates to 75 MMscf/D (2.1 × 10(6) std m3/d) per well from the top zone and 50 MMscf/D (1.4 × 10(6) std m3/d) per well from the bottom zone. F23 field is a platform-type carbonate buildup.

JPT

P. 688