Abstract

A 3 dimensional reservoir simulation model of the Harmattan East gas condensate field was linked with a surface facilities model in order to predict future gas deliverability and evaluate further capital expenditures, such as additional compression or horizontal infill wells. Using a more rigorous approach for this complex reservoir resulted in an increase in the estimated original gas in place, and allowed surface facility decisions to be tied to the infill drilling program. This model yielded more accurate results than a tank model because of the large permeability and pressure variations within the field.

Introduction

The Harmattan East field is located approximately 80 km north of Calgary, Alberta, Canada (Fig. 1). The field was discovered in 1956, and includes a large gascap with two attached oil columns. Currently there arc 32 wells drilled into the gascap. A gascap cycling scheme was implemented in 1962 to increase and accelerate the recovery of natural gas liquids, and to partially maintain oil column pressure (Fig. 2). Dry gas injection was stopped in 1991, when full blowdown of the gascap commenced. Gas production started in 1964 and reached a peak of about 4700 (E+03) m3/D in 1977. Production has declined by approximately 15% per year since 1992, dropping from 4000 (E+03) m3/D to about 2700 (E+03) m3/D at the beginning of 1995. The condensate gas ratio (CGR) has risen slightly to about 250 m3/(E+06)m3 since gas injection stopped.

Production is obtained from the Mississippian Turner Valley formation at a depth of about 2600 m. Typical reservoir parameters are presented on Table 1. Reservoir development occurs in zones of porous dolomite with associated beds of dense limestone. There are four distinct producing layers with limited vertical communication. The reservoir is bounded downdip by an erosional channel, and updip by erosional truncation of the Turner Valley formation. Communication between the gascap and the main oil column is apparently restricted by an erosional channel. The reservoir boundary to the north of the field is not well defined.

The main purpose of the simulation study was to predict the incremental deliverability resulting from an increase in facility compression. In addition, it was desired to confirm the original gas in place (OGIP), and to estimate the incremental production from infill wells.

A simulation study was considered necessary because the reservoir pressure in the gascap varies significantly over the 15 km from north to south (Fig. 3). For example, in 1992 the pressure in the low permeability northern areas was about 21 MPa, while the pressure in the south was about 7.5 MPa. This pressure variation complicates the determination of OGIP using a P/Z plot. Also, it is difficult to estimate the incremental production resulting from infill wells drilled in the high pressure areas of the field because these wells reduce the deliverability of existing wells by increasing the pressure in the gathering system. Finally, it is difficult to generate a production forecast for the case of additional compression using analytical techniques.

A black oil simulator was used for the study due to time constraints, and also because the liquid dropout in the reservoir as a percent of hydrocarbon pore volume is under 2.5%, which is relatively low for a gas condensate.

Reservoir characterization was the key to achieving an acceptable history match relatively quickly. The permeability-thickness (kh) varied from over 10,000 md-m in the south of the field to under 10 md-m in the north, and this had to be well represented in the model in order to achieve a match. The forecasts indicated that adding a second stage of compression would be economical.

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