Abstract
Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation.
Highlights
The booming of shale oil development has rapidly increased the amount of flared gas in the past decade in the United States (Figure 1)
After the shut-in period, the well is produced for 5 years with a decreasing downhole pressure from 32.8 MPa to 10 MPa for the duration of the production time
Simulation results during the injection, shut-in, and production periods are compared andSimulation analyzed the differences in the performance of the results during to thedemonstrate injection, shut-in, and production periods are comdifferent fluids
Summary
The booming of shale oil development has rapidly increased the amount of flared gas in the past decade in the United States (Figure 1). Due to the lack of pipelines in the major shale oil production sites, typically operators have no way to utilize the produced natural gas and so it must be flared or reinjected. Collecting the produced gas through pipelines and selling it as liquid natural gas. Storing the produced gas in suitable reservoirs. Injecting the stranded produced gas into the reservoirs for improved oil recovery [1], for example, gas huff-n-puff injection, gas flooding, and foam flooding. For example, gas huff-n-puff injection, gas flooding, and foam flooding. Using thethe produced natural gasgas forfor hydraulic fracturing [2],[2], forfor example, foam fracturing, natural fracturing
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