Impairment Mechanisms in Vicksburg Tight Gas Sands
- A. Abrams (Shell Development Co.) | H.J. Vinegar (Shell Development Co.)
- Document ID
- Society of Petroleum Engineers
- SPE/DOE Low Permeability Gas Reservoirs Symposium, 19-22 March, Denver, Colorado
- Publication Date
- Document Type
- Conference Paper
- 1985. Society of Petroleum Engineers
- 5.1 Reservoir Characterisation, 4.3.4 Scale, 4.1.2 Separation and Treating, 5.4.2 Gas Injection Methods, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.2.1 Phase Behavior and PVT Measurements, 1.6.9 Coring, Fishing, 5.8.1 Tight Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.8 Formation Damage, 2.4.3 Sand/Solids Control
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The flow of nitrogen and brine in tight Vicksburg "P" Sand cores was studied under field stress conditions. The experiments simulated various stages of a hydraulic fracturing treatment. Measurements were made of critical gas saturation, gas flow vs pressure gradient, and gas permeability vs brine pressure gradient, and gas permeability vs brine saturation. Brine saturations were imaged with a medical Computerized Tomography (CT) scanner.
The laboratory results suggest that water block is not important when drawdown pressures at the fracture face exceed the capillary entry pressure by several hundred psi. The addition of alcohol or an alcohol/surfactant package to the brine does not significantly increase final gas flow.
Production problems with tight gas sands have been Production problems with tight gas sands have been discussed in many papers. Poor gas production from tight rock following a water-base fracture treatment is often attributed to water block. In water-wet rock, capillary forces resist brine displacement from the matrix into the fracture. Water block occurs if the drawdown pressure gradient in the formation near the fracture face does not exceed the rock capillary pressure sufficiently for gas to flow.
In 1979, Holditch reported results of a numerical simulation of water block in tight formations. He concluded that water block is not a serious problem in most tight formations because drawdown pressure and water mobility are usually high enough for efficient displacement of fracture fluid from the formation. However, water block may develop if reservoir pressure gradients in the near fracture face region are low or if fluid mobilities are seriously reduced by formation damage.
Several aspects of gas flow in tight rock were also studied in the laboratory. They also indicated that water mobility is probably high enough so that final gas production is not affected by water block.
Nevertheless, there is continued effort in the industry to develop fracture fluid additives designed to overcome water block and increase gas production. Many additive packages such as alcohol production. Many additive packages such as alcohol and alcohol/surfactant are commercially available. A detailed review of one such package, including field test data, has been published by Penny, Soliman, Conway, and Briscoe. They claim Penny, Soliman, Conway, and Briscoe. They claim that "oil wetting" (reducing water wetting in a gas-water system) the rock surface would lower the capillary pressure sufficiently to reduce both water blocks and brine imbibition. As a result, the volume of invaded brine would be reduced. A further benefit would accrue from increased water mobility during gas displacement due to surface tension reduction. Field examples are cited which show improvements in both load water production and gas production.
In order to resolve the controversy over the significance of water block in hydraulic fracturing of tight gas sands, a laboratory study was initiated using a CT scanner to measure brine saturations and fluid flow under stress conditions that simulate a hydraulic fracture.
In this study, reference gas and brine permeabilities were first measured at downhole permeabilities were first measured at downhole pressure conditions. A gas drawdown test was pressure conditions. A gas drawdown test was developed to measure gas flow following the fracture treatment. Gas flow following and gas permeability were measured as the pressure gradient was increased. Drawdown tests with alcohol and the alcohol/surfactant packages were included for comparison with brine fracture fluids.
Tests were conducted at ambient temperature and reservoir effective overburden pressure (core overburden pressure - pore pressure).
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