Improvement in hydrocarbon production from unconventional reservoirs, such as the Bakken Formation, is driven by drilling horizontal wells and multi-stage hydraulic fracturing. The success of the treatment relies substantially on selecting appropriate fracturing fluids that transport the proppant particles deep enough into the fractures. This research is aimed at studying the capability of high-viscosity friction reducers (HVFRs) by examining the produced water from the Bakken Fm through an integral approach. The application of surfactant as an additive to the HVFRs was investigated in high TDS (total dissolved solids) conditions. To assess the current industry practice for hydraulic fracturing in the Williston Basin, these tasks were performed: a) rate trainset analysis (RTA) to evaluate the current completion in Bakken wells by estimating fracture half-length and SRV properties, b) 2D/3D fracture simulation to study the impact of treatment fluids on fracture-network/SRV properties, c) sensitivity analysis were performed to reduce uncertainty of hydraulic fracturing design parameters, and d) reservoir simulation to predict the estimated ultimate oil recovery (EUR) for identifying optimum hydraulic fracturing design. The results show that using a surfactant mixed with the frac fluids can lead to improved proppant transport, fracture conductivity profile, and thus higher effective fracture-half length compared to current practice. It was found that such a frac fluid mixed with surfactant can result in improved EUR by as high as 15% compared with linear gel and HVFRs with produced water (HVFR-PR) due to larger SRVs. Reusing produced water, including formation and flow back water can be a wise decision to minimize environmental footprint and reduce operating costs.


A revolution of unconventional reservoirs is a turning point in the global oil and gas industry since these resources have massive reserves with large potential in contributing to hydrocarbon production. In recent years, the domestic oil production from liquid-rich shale (LRS) reservoirs in North America has a great development, and the production dramatically increased in the Bakken, Eagle Ford, and Permian Basin from 16.5% in 2008 to reach around 60% in 2019 of the total U.S oil production from conventional and unconventional reservoirs (The Energy Information Administration (EIA), 2019). Currently, these shale plays have the most drilling rig and completion activities in the U.S, and the number of wells in each play is over 12,000 wells producing oil/gas (Drilling Info, 2020; Fracfoucs, 2020; EIA, 2020). EIA outlook data in 2050 show that the U.S shale plays daily production rate will be extended to 70% of the total U.S daily oil production. This improvement in hydrocarbon production is driven by applying modern horizontal drilling and multi-stage hydraulic fracturing that make it a reality to access low porosity (<10%) and low permeability (<0.1 mD) formations (Ellafi et al., 2020a; Ba Geri et al., 2019a; King, 2010). In the Bakken formation, a complex-fracture geometry system is often generated as a result of significantly distributed in natural fractures. Therefore, the success of the treatment strongly relies on selecting appropriate design parameters: Treatment fluids, proppant type, completion method (diversion/isolation), design of refrac stages, and the selection of proper well candidate (Ellafi et al., 2020; Ba Geri et al., 2019b; Shah et al., 2017). The treatment fracture fluids can transport and fill the proppant particles deeper into the fractures by creating large stimulated reservoir volume (SRV). On the other hand, unsuccessful implementation design causes lower incremental oil recovery from SRV (Ba Geri et al., 2019d; McMahon et al., 2015; Li & Zhang, 2019). The current options that are used and gaining more attention in the industry to revive the performance in unconventional wells are infill drilling and/or refracturing treatment applications. The refrac treatment is performed by injecting fracturing fluids, such as high viscosity friction reducer (HVFRs) through the fractures of the previous job and/or new entry points to create new fracture clusters with smaller fracture spacing in order to enhance production performance (Ellafi et al., 2020; Ba Geri et al., 2019). Based on the drilling spacing unit (DSU) and governmental regulations, up to 20 wells can be drilled and stimulated from a single well pad to produced economically from unconventional shale plays (Ahmed and Meehan, 2016). However, these development applications of shale reservoirs have reached a challenging point, where the operators in North America face problems in terms of management and environmental issues. This study is an extended work to our previous publications (Ba Geri et al., 2019 and Ellafi et al., 2019) to study the capability of HVFRs with produced water in unconventional rich liquid reservoirs (ULR) using an integral approach (3D/2D Pseudo hydraulic fracturing simulator and numerical reservoir simulation). In this paper, optimizing hydraulic fracturing treatment is applied using Rate Transient Analysis (RTA) to enhance Bakken oil production by improving fractures networks around SRV using HVFRs with a surfactant in high TDS environment. The design parameters considered in the sensitivity study include fracturing fluid types, pump rates, proppant concentrations, and proppant sizes to obtain optimum conditions under which the incremental oil recovery and fracture geometry from the Middle Bakken well are increased.

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