No abstract

No abstract

No abstract

Aimed at advancing gas injection enhanced oil recovery (EOR) technologies in unconventional reservoirs, this study comprised a series of activities to bridge the gap between the theoretical study and actual field applications. Twenty-four EOR pilot tests were collected from the major unconventional plays in North America to evaluate the performance of different EOR technologies. Fit-for-purpose experiments and simulations were performed to investigate the effects of injection rate and pressure on EOR performance, as well as to reveal the effectiveness of huff "n" puff (HnP) cycles in actual field operations. The selection of injection rate and pressure as key parameters for investigation was based on field observations and communications with oil and gas operators because these two parameters play critical roles in both facility design and overall cost for an EOR project. Results showed that miscible EOR with a high gas injection rate and pressure is required for field operations because the injected gas needs to penetrate and extract oil from the tight matrix. Experimental results indicated that there is a correlation between oil recovery and the logarithm of core volume for miscible EOR. Immiscible gas EOR could not yield a satisfactory EOR response in actual reservoirs because the injected gas tends to flow through fractures instead of penetrating the matrix to interact with oil. Results also showed that reaching minimum miscibility pressure (MMP) does not guarantee an optimum EOR operation in unconventional reservoirs. Pressure higher than MMP is preferred in field operations. When designed properly, up to a tenfold oil production rate boost is achievable in field applications within a short period. However, such a high-performance operation is only effective in the first several HnP cycles due to the limited gas penetration depth into the rock matrix.

Improvement in hydrocarbon production from unconventional reservoirs, such as the Bakken Formation, is driven by drilling horizontal wells and multi-stage hydraulic fracturing. The main objective of a frac treatment is to create complex fracture geometry to increase well/reservoir contact area (i.e. large SRV; stimulated reservoir volume) by injecting larger fluid volume and high proppant concentration. 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 estimatingfracture half-length and SRV properties, b) 2D/3D fracture simulation to study the impact of treatment fluids on fracture-network/SRV properties, and c) reservoir simulation to predict the estimated ultimate oil recovery (EUR) for identifyingoptimum 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 tocurrent 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. The findings from this research can be applied to other unconventional shale plays, such as Eagle Ford and Permian Basin for comparison and optimization purposes.