(353c) Developing a Closed-Loop Optimum Pumping Sequence with Shear Thinning Fluid for Enhanced Hydraulic Fracturing

In the United States, 30% of the total energy comes from natural gas, and shale gas continues to make a major contribution to the total Natural Gas production of the nation^[1]. Hydraulic fracturing and horizontal drilling are the two major technologies that have made the commercial extraction of hydrocarbons from unconventional reservoirs economically feasible. Specifically, hydraulic fracturing is carried out with slick water, which leads to huge water leak off into the formation and produces (artificial) hydraulic fractures^[2].

In recent years, hydraulic fracturing with high-viscosity gels has been one of the most explored topics both in theory and practice. The use of high viscosity gels has resulted in fractures with higher fracture conductivity and longer propped length^[3-5]. The most commonly used gels in hydraulic fracturing are shear thinning fluids which sufficiently reduce pressure drop at the wellbore and fractures. One of the major problems associated with using these gels is that they leak off into the reservoir and eventually cause formation damage by chocking pore throats. These gels also lead to sufficient damage inside the fractures by mechanisms like proppant crushing and cake deposition. The formation and fracture damage phenomenon are sometimes very severe and can have a significant negative impact on the oil and gas production^[6-8]. However, there is a dearth of study that considers all these factors and proposes an optimal operation sequence for practice. Consequently, the current challenge for the operators is the choice of a gel viscosity that would lead to minimum formation and fracture damage along with determining the proper pumping schedule to achieve optimal fracture geometry.

The work presented here attempts to address this challenge by proposing a novel methodology that can be used for deriving the optimal operating parameters for hydraulic fracturing with gels. Specifically, a novel model describing fracture propagation and multiphase reservoir behavior is developed. This model precisely predicts the formation damage phenomenon due to the leak-off of high-viscosity gel and also predicts the fracture damage due to filter cake deposition. Once the formation and fracture damage are modeled, they are used as the initial conditions for predicting the oil and gas production from a reservoir by utilizing a three-dimensional in-house reservoir simulator. The sensitivity analysis of hydrocarbon production is performed by adjusting three parameters, which are the gel viscosity, average fracture conductivity and propped surface area. The sensitivity analysis gives us a value of gel viscosity at which the maximum oil and gas production is achieved. The optimal value of gel viscosity is then used in developing a pumping schedule to attain the optimal values of average fracture conductivity and propped surface area. Since pumping operation in practice is a multi-input and multi-output system, a closed-loop model predictive controller (MPC) is designed to get an optimum pumping schedule. Specifically, the flow rate of gel and concentration of proppant are the two manipulated inputs, and average fracture conductivity and propped surface area are the two outputs. Additionally, several practical considerations are incorporated through constraints like the maximum amounts of fluid and proppant to be injected. This closed-loop MPC scheme is developed by utilizing a computationally less intensive reduced-order model for the process followed by the development of a Kalman filter to estimate the unmeasurable states using feedback measurements from the process. The MPC problem is formulated including the constraints and the reduced order model, and since, the operation time is fixed it becomes a shrinking horizon closed-loop optimization problem which is solved to obtain the optimal input for each time interval. This closed-loop structure of the proposed methodology extends its application to real-time operations where a plant-model mismatch is plausible. In summary, this work shows that for a given reservoir, we can calculate the viscosity of fracture gel using which an optimum pumping schedule can be obtained for the maximum oil and gas production from that reservoir.

Literature Cited:

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[2] Jr., Alfred Jennings. “Fracturing Fluids - Then and Now.” Journal of Petroleum Technology, vol. 48, no. 7, 1996.

[3] Clark, J.b. “A Hydraulic Process for Increasing the Productivity of Wells.” Journal of Petroleum Technology, vol. 1, no. 01, Jan. 1949.

[4] Seright, R.s. “Use of Preformed Gels for Conformance Control in Fractured Systems.” SPE Production & Facilities, vol. 12, no. 01, Jan. 1997.

[5] Al-Muntasheri, Ghaithan A. “A Critical Review of Hydraulic Fracturing Fluids over the Last Decade.” SPE Western North American and Rocky Mountain Joint Meeting, 2014.

[6] Wang, Yilin, et al. “Simulation of Gel Damage on Fracture-Fluid Cleanup and Long-Term Recovery in Tight-Gas Reservoirs.” SPE Eastern Regional/AAPG Eastern Section Joint Meeting, 2008.

[7] Maloney, Daniel R., et al. “Non-Darcy Gas Flow Through Propped Fractures: Effects of Partial Saturation, Gel Damage, and Stress.” SPE Production Engineering, vol. 4, no. 04, 1989, pp. 417–422.

[8] Yi, X. “Model for Displacement of Herschel-Buckley Non-Newtonian Fluid by Newtonian Fluid in Porous Media and Its Application in Fracturing Fluid Cleanup.” SPE International Symposium and Exhibition on Formation Damage Control, 2004.