Summary

A pilot steamdrive test has begun in the Marmul oil field in south Oman. It is intended that 1,774 U.S. tons/D [1610 Mg/d] of dry saturated steam will be injected into the test area for approximately 5 years to test the steamdrive process quantitatively. The surface facilities, consisting of a water treatment plant and steam generators, have been designed for reliable operation in the hot, remote desert environment.

Introduction

Steamdrive is now a reality in the oil fields of the Sultanate of Oman. Plans for testing a variety of EOR techniques in Oman were Plans for testing a variety of EOR techniques in Oman were presented in Ref. 1. Steamdrive was one of the most promising methods presented in Ref. 1. Steamdrive was one of the most promising methods then proposed. This paper deals with the design, construction, and initial operation of a pilot steamdrive project in the Marmul heavy-oil field, south Oman. This is the first steamdrive project carried out in Oman and possibly in the Arabian Gulf. It is the first in a series of such developments planned for south Oman, where significant heavy-oil discoveries have been made during the last 5 years.

The Marmul field contains 2,453 × 10 bbl [390 × 10 m3] oil in place (21 to 23API [0.93 to 0.92 g/cm3]) with a viscosity ranging from 50 to 140 cp [50 to 140 mPa s]. This high oil viscosity causes an unfavorably high mobility ratio for waterdrive with the prospect of an ultimate recovery of about 20%. The prospect of an ultimate recovery of about 20%. The implementation of a steamdrive could significantly enhance oil recovery. The objective of this pilot is to test the steamdrive process quantitatively to enable direct extrapolation and optimization of a large-scale project and to verify reservoir simulation studies. A secondary objective is to gain experience with steamdrive in the harsh, remote environment of the south Oman desert.

The pilot calls for the injection of 1,774 U.S. tons/D [1610 Mg/d] dry saturated steam at 1,740-psi [12-MPa] wellhead pressure and 617F [325C] for 5 years. The test area consists of nine production wells and four injection wells in an inverted five-spot pattern production wells and four injection wells in an inverted five-spot pattern with a 696-ft [212-m] grid spacing (Fig. 1). It was recognized at an early stage that the relatively high injection pressure, the remote desert location, and the importance of a successful first trial demanded that special attention be given to all aspects of the project.

Overall Description

The facilities, which were commissioned during Sept. to Dec. 1984, are shown in Fig. 2. Untreated water is drawn from four water wells with submersible electric pumps and is delivered through a 6-in. [15. 24-cm] internally coated steel line to the water treatment plant. The water then passes directly through pressure sand filters plant. The water then passes directly through pressure sand filters and two stages of softening, and is collected in two 6,290-bbl [1000-m3] storage tanks. From these feedwater tanks, it is pumped through a steam deaeration vessel to five horizontal-tube oilfield steam generators, each with 443-U.S.-ton/D [402-Mg/d] steam capacity. One of these generators is always in maintenance or on standby so that effective capacity is 1,774 U.S. tons/D [1610 Mg/d]. The 70 to 80%-quality steam leaving each generator is passed through a separation vessel to remove unevaporated water that is discharged, after heat recovery and cooling, to a wastewater system. The dry saturated steam is distributed through an 8-in. [20.3-cm] header, about 0.6 miles [1 km] long, to the four injection wells in the nearby field. This header slopes continuously toward the wells, allowing a very high turndown without the risk of unstable two-phase flow resulting from condensate collection at low points.

Oil from the test area is collected in a dedicated oil-gathering station next to the steam facilities. The gas is then separated and compressed for burning as fuel in the steam generators. A test separator is used for regular three-phase testing of each well. Two 8,800-bbl [1400-m3] surge tanks provide at least 24 hours of residence time for emulsion-breaking chemical treatment should emulsion problems occur.

Two high-pressure reciprocating compressors provide a secure supply of sweet gas that is distributed to the steam-injection wells, where it is pressured into the annulus between the tubing and innermost casing. The injection tubing is insulated to reduce heat loss and to limit casing temperature. The continuous injection of gas into the annulus ensures that no water enters the annulus through the packer. This is important to prevent excessive heat transfer, either through-the water or by refluxing, to the casing, which could be overstressed at the high injection temperatures used.

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