Abstract

The Bearberry ultra-sour reserves contain 90% H2S and up to 100 Mt of Sulphur, This discretionary source of Sulphur was recently brought into production from two wells to a nearby processing plant to demonstrate its technical viability. At reservoir conditions (37 MPa, 118 °) the 90% H2S contains significant dissolved elemental sulphur which precipitates in the formation and wellbore during production. One well was perforated over a limited interval to accelerate sulphur precipitation and deposition in the near wellbore region, thus simulating the long term production performance of future commercial wells. The harsh environment presented many challenges to completion design. Unique equipment and production techniques were required. Continuous circulation of a sulphur solvent was required to prevent plugging of tubing and flowlines. Corrosion prevention in the 90% H2S environment containing wet, elemental sulphur was a major challenge. The solvent oil contained a corrosion Inhibitor and all components not contacled by the inhibited solvent were made from corrosion resistant alloys. Jet pumps provided artificial lift for the dense (690 kg/m3) reservoir fluid mixed with solvent oil. Permanent gauges with continuous surface readout measured downhole temperature and pressure, and helped quantify the impact of sulphur deposition on production performance.

Introduction

Canada ranks third in world production of elemental sulphur and is the world's largest sulphur exporter. In recent years (19860–1990), annual sales from Canada have averaged 6.1 Mt. Alberta is a major producer of elemental sulphur accounting for 88% of Canada's production.1 Most of this sulphur is non-discretionary or nvoluntary production derived from processing sour (H2S) natural gas produced from deep carbonate reservoirs found in the foothills of the Rocky Mountains (Fig. 1). Over the past decade, shortfalls between demand and non-discretionary production have been made up by remelt of sulphur block pad inventories stockpiled adjacent sour gas plants during the 60s and 70s when demand was low. Fromapeakof21 Mtin1978, inventories have declined to 3.5 Mt in 19902

In 1969 Shell discovered a sour gas reservoir at 3755 m in the Devonian Leduc reef at Bearberry (Fig. 1) with the drilling of the Shell-Canadian Superior 12-21-33-6 W5 well. Amazingly the reservoir fluid was found to contain 90% H2S (see Table 1 -Gas Analysis) and the Bearberry accumulation to this date has remained the highest H,S content reservoir discovered in Canada. The nearby Harmattan Leduc field with some 50% H2S was at that time the highest H2S reservoir commercially produced and at Panther River (Fig. 1) Shell had tested wells with 73% H2S during tile 1960s. Subsequently two delineation wells successfully penetrated the Bearberry structure: Mobil Banner James 11-35-33-7 W5 (1970) and Shell-Canadian Superior 16-32-32-6 W5 (1978).

The Bearberry 12–21 well was production tested for seven weeks shortly after the well was drilled. Based On Shell's previous experiences at Panther River with production testing similar ultra-high H2S wells, a continuous downhole hydrocarbon circulation system with dual tubing strings was used to prevent sulphur deposition and plugging.

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