The most commonly used technology for development of unconventional liquid-rich and light oil reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10% (Shoaib and Hoffman, 2009) of the original oil in place (OOIP). Logically, operators have investigated the use of waterflooding to improve recovery in some tight oil reservoirs, but the success has been mixed. Low matrix permeability in some unconventional (tight) oil reservoirs will not allow effective displacement or movement of water through the reservoir. In some cases, even flooding with a gas will be a challenge, if matrix permeabilities are too low. This study investigates the feasibility of enhanced oil recovery (EOR) in a prominent tight oil reservoir in North America using cyclic solvent injection (CSI, sometimes referred to as "huff-n-puff") with carbon dioxide (CO2) as the solvent. CSI is a single well process, with the solvent remaining in the vicinity of the wellbore, as flow of the solvent through the reservoir to another well is not necessary. This type of process may be attractive from a capital cost point-of-view, as large expenditures on specialized facilities, in-field pipelines and well conversions are unnecessary. In this study, the success and profitability of huff-n-puff is evaluated for the Bakken tight oil reservoir. Knowledge gained from a parallel study (Kanfar and Clarkson, 2017) served to provide guidelines for optimizing the huff-n-puff process. Importantly, a genetic algorithm (GA) is utilized to find the optimum huff-n-puff program that maximizes net present value (NPV). Optimized parameters include: the number of cycles; duration of injection, soaking and production periods; and the start time of huff-n-puff operations. The target reservoir for evaluation is the US Bakken deep tight oil reservoir in North Dakota. The huff-n-puff EOR scheme was found to be successful, but only after the aforementioned operational parameters are optimized with GA. In particular, it is important to delay huff-n-puff until production rates decline and boundary-dominated flow (after fracture interference) is reached. Importantly, as with the parallel study (Kanfar and Clarkson 2017), the gridding scheme used in the simulation is found to have a profound impact on results of huff-n-puff.

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Recently, there has been discussion of the need to advance hydraulic fracturing technology from the current ‘operational effectiveness’ mode of high-rate slickwater fracture designs, to a ‘fracture effectiveness’ mode provided by optimizing designs to achieve higher recoveries and better economics. This case study shows how advanced fracture fluid system designs have increased fracture effectiveness in an area of the Montney unconventional gas play. The study focused on fifty multi-stage fractured horizontal wells in the dry gas area of the Heritage Montney Field in British Columbia, Canada. These wells were stimulated by different operators with a number of different fracturing techniques, fluid systems, etc. Wells were selected such that a sufficient variety of completion techniques were represented, and there was over 18 months of production history. A thorough review of the geology and petrophysical data within the area was undertaken in order to develop individual well descriptions for use in the production analysis (Rate Transient Analysis). Wells were history matched by varying reservoir permeability and fracture treatment properties. The results demonstrate that fracture effectiveness is a function of the fracture type and has a large effect on well productivity and economics. This case study shows there is value in optimizing fracture designs through look-back studies, and that there is a need to focus on more effective fracture treatment designs in unconventional gas development. The results of the study show the importance of fracture fluid selection as well as both effective fracture half-length and fracture conductivity in maximizing the economic returns in this area of the Montney.

The Horn River Basin covers an estimated 3 million acres in a remote and difficult to access area of northern British Columbia. A number of Operators have experimental projects in the area, using various drilling and completion techniques, in order to evaluate the shale reservoir, gas in place, and productivity; moving towards commercial projects. The Devonian age shales of the Horn River Basin have been compared to the Barnett Shale of the Fort Worth Basin, in terms of reservoir quality, productivity and recovery factors. This paper will review the following important aspects of the Horn River shale area: History of the play;General review of the Geology, reservoir properties, thickness, gas content, gas in place, permeability, etc.;Emerging drilling and completions techniques, well construction, stimulation practices, fracture diagnostics, logistical problems;Production tests, well initial productivities, and longer term production forecasts, estimated recovery factors;Production and Operations challenges;Development costs and economics;Future development hurdles, what is needed to make this play commercial?

The most commonly used technology for development of unconventional reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10 percent of the hydrocarbon in place. Water is currently the primary fracturing fluid used in most commercial developments. There is growing interest in non-aqueous (e.g. CO2) fluid systems not only to reduce water usage, but to increase well productivity and recovery factors. Use of carbon dioxide (CO2) as a fracturing fluid and an enhanced oil recovery (EOR) agent is also attractive from an environmental point-of-view. Organic rich shale reservoirs can be targets for carbon storage, due to their high CO2 adsorptive abilities and multiple mechanisms for gas storage. Therefore, use of CO2 can have both economic (increased recovery) and environmental (sequestration) benefits. This laboratory study investigates the interactions of CO2 with various cores from three formations (Duvernay, Montney, and Wolfcamp). Multiple core plugs were prepared from each of the three reservoirs. The mineralogy of the samples was measured with x-ray diffraction (XRD), and total organic carbon (TOC) and thermal maturity were determined with a SRA (Source Rock Analyzer). Porosity was also measured under as-received conditions and cleaned and dried conditions with a helium pycnometer. For each sample, its initial baseline permeability to helium was tested under a full cycle of net confining pressures (1,500 psia → 4,500 psia → 1,500 psia) with pressure steps of 1,000 psia using the pressure pulse-decay method. Subsequently the sample was vacuumed for 12 hours, and was then soaked with CO2 for more than 48 hours. Afterwards, the permeability to CO2 was measured under another cycle of confining pressures. Finally, the sample was vacuumed again and the regain permeability to helium was measured. Results indicate that the permeability to helium is generally recovered after CO2 soaking stages for tight-sand samples (e.g., Montney) and may be elevated for some samples enriched in organic matter and clay minerals (e.g., Wolfcamp). Overall the study shows favorable interaction between rock and organic material and CO2, which supports the use of CO2 as a fracturing or EOR fluid in these three reservoirs.