--> --> Optimal Stimulation Treatments in Tight Gas Sands, by Stephen A. Holditch; #90042 (2005)

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Optimal Stimulation Treatments in Tight Gas Sands

Stephen A. Holditch
Texas A&M University, College Station, TX

Tight gas reservoirs have been exploited in the United States since the 1960’s. However, it was in the 1970’s when higher prices for natural gas and tax incentives from the government led to the rapid increase in drilling and completion activity in tight gas reservoirs. In the late 1970’s, Masters and Grey published the concept of the Resource Triangle to explain the distribution of natural gas in the Deep Basin in Alberta. However, the concept of the Resource Triangle applies to all oil and gas basins and the consequences of the distribution should be understood by anyone trying to develop tight gas or other unconventional reservoirs. If one looks at the distribution of natural gas resources, it is obvious that as the quality of the natural gas resource decreases, the size of the resource increases substantially. It is also clear that higher revenue (gas prices) and better technology are required to produce the low quality resource economically.

The most important technology contributing to the economic success in tight gas sands is hydraulic fracturing. In the 1960’s, the industry was using water fracture treatments carrying small volumes of sand to stimulate tight gas reservoirs. In the 1970’s and 1980’s, viscous, cross-linked polymer fluids were used to carry larger volumes of sand to better stimulate tight gas reservoirs. In the 1990’s, some in the industry returned to pumping larger water fracture treatments, first in the Austin Chalk, and later in certain gas shales and also in some tight gas sands. In some cases, the water fracture treatments appeared to work better than the viscous gel treatments.

Currently, there is a lot of confusion concerning the optimum fracture fluid and proppant type for certain tight gas reservoirs. The most confusion occurs when the formation temperature is between 200-250°F. At that temperature, viscous, cross-linked polymer fluids can sometimes damage the reservoir if proper additives are not used. In this paper, I will lay out some of the problems and suggest a way forward that will allow operators to better choose the optimal stimulation type for a given tight gas reservoir.