Abstract

Gelled hydrocarbon has been used as a fracturing fluid from the early days of fracturing. Its use internationally has been prevalent; and continues to the present day in Canada, South America, Russia and East Asia. The paper will discuss the use of gelled oil fluids in Canada, particularly in lowpressure tight gas wells, where the use of CO2 energized gelled hydrocarbon fluids have been very successful. The chemistry of these fluids and their application is discussed. The energized fluids have been used varied formations with permeabilities from 0.1 mD to 10 D, depths in excess of 3000 m and BHT from 10 to 110 °C. Initial and longer-term production data from wells treated with the energized fluid will be compared to wells treated with conventional gelled hydrocarbon fluids to show the effectiveness of the system in tight gas applications.

The case study will include wells treated and producing from the Rock Creek oil, Dunvegan, Glauconite and Belly River gas formations in the Western Canadian Sedimentary Basin (WCSB). Observations on proppant selection and in-situ closure stress are made in addition to the fracturing fluid selection.

Introduction

Natural gas currently accounts for 22% of world wide energy consumption. As worldwide use of natural gas is increases to meet energy demand, interest in unconventional gas increases. This includes coal-bed methane, tight-sand gas, shale gas and gas hydrate wells. Commercial production of unconventional gas is still in its infancy with development of tight gas, coal-bed methane and shale gas performed mainly in North America. Resource assessment data of unconventional gas varies widely; however, it is universally accepted that the unconventional gas resource base, excluding gas hydrates, is more than twice that of conventional gas. Gas hydrates are excluded due to limited technology and success at developing the resource. In North America, gas resource from tight sands is estimated to be around 1371 Tcf (1). Unconventional gas production was only 1 Tcf / year in the 1970s, but has increased to around 4 Tcf / year in 1997 which accounted for 20% of the national gas consumption (2). Almost 70% of unconventional gas production is from tight sands.

The definition of tight gas is somewhat arbitrary, but is generally accepted to mean from formations with an average air absolute permeability less than 20 mD. In-situ permeabilities in these types of reservoirs are generally less than 1 mD and can range down into the micro-Darcy range (10–6 D) in many cases.

Using appropriate drilling, completion and in some cases large-scale fracturing techniques, operators have succeeded in obtaining economic production rates from formations exhibiting in-situ matrix permeabilities as low as 10–6 D. In many cases, gas may exist in such low permeability formations, but its production is challenged due to adverse capillary forces, high in-situ saturations of trapped water, and in some cases, the presence of liquid hydrocarbons. If these saturations are too high, economic production from the zone is difficult without appropriate fracturing techniques.

Tight gas reservoirs are susceptible to formation damage during drilling and completion operations. Low permeability formations tolerate only minimal damage.

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