Stimulation Results in the Low-Permeability Wasatch Formation: An Evolution to Foam Fracturing
- P.C. Harris (Halliburton Services) | D.E. Bailey (Halliburton Services) | G. Evertz (MAPCO Inc.) | T.L. Reeves (MAPCO Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1984
- Document Type
- Journal Paper
- 1,545 - 1,551
- 1984. Society of Petroleum Engineers
- 1.14 Casing and Cementing, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.5.8 History Matching, 5.1.1 Exploration, Development, Structural Geology, 4.1.2 Separation and Treating, 2.2.3 Fluid Loss Control, 5.2 Reservoir Fluid Dynamics, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 2.5.1 Fracture design and containment, 2.2.2 Perforating, 1.2.3 Rock properties
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The Wasatch formation of the Uinta basin in eastern Utah is typical of many formations in the Rocky Mountains, having low permeability and high sensitivity to water.
Stimulation treatments with several types of fracturing fluids, including oil-in-water emulsion fluids, complex get fluids, and foam fluids, have been generally successful.
Production decline curves from 24 wells in the field were used for comparison of the different stimulation methods. Although foam fracturing has been used for the shortest period of time, comparison of the production histories shows the relatively higher efficiency of the foam fracturing treatments compared to other stimulation methods in the Wasatch formation. Foam fluids gave higher production rates and higher flowing pressures than offset wells fractured with complex gel fluids.
A simulation model for oil and gas production was used to match the production history from this reservoir. The model allowed a projection of gas production based on early production from the wells and knowledge of the reservoir.
There are many tight gas reservoirs in the Rocky Mountains that have low permeability and high water sensitivity and require stimulation to make them commercially productive. Low-permeability sandstones often have a productive. Low-permeability sandstones often have a small capillary network that tends to retain fluid. Fluid sensitivity may result from the presence of clays that can swell or migrate after water contact. The Wasatch is such a typical formation.
In an attempt to make the formation commercially productive, stimulation efforts have undergone an productive, stimulation efforts have undergone an evolutionary process. The predominantly sandstone formation gives no initial production. Deep, propped fracture treatments served to improve and extend productivity. Oil-in-water emulsions were used initially to create fracture geometry and place proppant. But exact blending requirements and high frictional losses in pumping the treatments gave disappointing results. Complex gels produced high-viscosity fluids with lower frictional losses produced high-viscosity fluids with lower frictional losses resulting in better stimulation at lower cost. But the water sensitivity of the low-permeability Wasatch made it desirable to reduce the liquid burden on the formation. Foam fracturing made it possible to drastically reduce the liquid placed on the formation, place higher proppant concentrations with less water than complex gel, and provide an energy-assisted rapid cleanup of the fracture. provide an energy-assisted rapid cleanup of the fracture. Characteristics of the Wasatch Formation
The Wasatch formation of the Uinta basin in north-eastern Utah originated in the Tertiary period of the Cenozoic era. Sediments were deposited within alluvial, deltaic, and lacustrine environments. The vertical extent of the formation varies from about 2,000 ft [610 m] along the south portion to near 4,000 ft 11,220 m] in spots on the nonhem end. Crossflow as well as under-pressured thief zones are common to the formation. The formation is composed of fractured sandstones, limestones, and dolomites lying within a massive shale section. The natural fractures often are filled with acid-soluble material such as calcite. The low permeability of the rock renders these fractures important to production. Dilute hydrochloric acid solubility ranges from 6 to 18% within the field of this study.
Petrographic thin-section analyses were performed on cores from several wells. The following analyses were typical.
Cherty Sandstone, 5,839 ft [1780 m]. These cores showed moderately sorted, medium-to-finely grained quartz, chert. feldspar, and detrital mica as framework grains. Intergrain pore space had been coated initially with mixed-layer clay then the overgrowth cemented. Remaining pore space was partially infilled with calcite, dolomite, and kaolinite material.
Sandstone, 6,325 ft [1928 m]. These cores revealed moderately sorted, medium-to-very-fine sand of quartz, altered feldspar (altered to mixed-layer clays), chert, and mica fragments as the framework grains. Some detrital chlorite is present. but most chlorite occurs as rims on crystal outlines. Calcite cements many pores, but the remaining pore space is clean.
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