Enhanced oil recovery in unconventional plays has been a focus of many E&P operators to increase recovery factors. Conventional displacement-based secondary (e.g. water flooding) and tertiary EOR methods are not viable options due to their low injectivity in these ultra-low permeability formations. As such, huff-n-puff (HnP) EOR techniques involving field gas injection may be the most effective EOR methods to increase the recovery factors from these shale formations. Several numerical reservoir simulation studies have showed the efficiency of CO2 HnP process in shale and tight formations (Yu et al, 2014); however, these studies show little to no field results to support the simulation predictions. This paper describes the conceptual development of the reservoir simulation models to investigate the viability of gas injection HnP in unconventional reservoirs and the results of applying those methods in Eagle Ford field test sites. Single-well and multi-well models with multi-stage hydraulic fractures were constructed and history matched using their primary production period performance. Sensitivity studies were conducted on well communication behavior/impacts, injection gas compositions, injection rates, injection/production cycling, and reservoir fluid types to optimize the pilot project well location(s) and to inform development strategies. Optimal cases from the simulation study were successfully applied to multi-well pads in the Eagle Ford formation across multiple fluid types. The simulation and the field application results were summarized and compared to provide detailed insights of unconventional HnP EOR. This study indicates the importance of confinement of the gases to afford optimal recovery factors during unconventional gas HnP EOR. An optimization engine was used in this study to optimize key operational parameters, such as injection pressures and slug sizes, to maximize recovery and efficiency. The resulting EOR designs were successfully implemented in field operations. Field recovery factors are within 10% of those predicted by simulation, indicating the value of numerical reservoir simulation prior to field trials and subsequent future development.
The Utica Shale is a very large, important oil and gas resource in the eastern United States. While gas production dominates, oil production from horizontal shale oil wells in the Utica has grown from 15 BOPD in June 2011 to a peak of 50,000 BOPD in September, 2019 with 2,485 horizontal shale oil wells in production. The Utica shale dips to the east, shallow in east-central Ohio to deep in western Pennsylvania. Likewise, hydrocarbons in the Utica trend from light oil with low GOR in eastern Ohio to dry gas in western Pennsylvania. Liquid hydrocarbons are produced from the shale via solution gas drive. The shallow, black oil area of the play has to date been noncommercial. A recent enhanced oil recovery test in the shallow black oil area of the Utica has provided encouraging results. Our objective is to introduce two novel EOR processes that can greatly increase the production and recovery of oil and gas from the Utica shale, while reducing the cost per barrel of recovered oil, and reducing GHG emissions and water consumption/production/disposal. Two superior shale oil EOR methods are proposed that utilize a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. One of the methods also incorporates the application of rock mechanics to further enhance oil and gas recovery. The processes are designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation model of a Utica shale horizontal well producing rich gas condensate was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate two novel shale oil EOR methods under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation via the SuperEOR method. A further enhanced EOR method, UltraEOR, is shown to potentially increase oil recovery by 850% in the first five years of EOR operation, and as much as 1100% after 12 years. These methods, which are patent-pending, have numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, reduced gas containment issues, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions. These superior shale oil EOR methods have been modeled in seven major US shale oil plays, indicating large incremental oil recovery potential. Core tests have confirmed the SuperEOR modeling results and demonstrated high oil recovery, and field tests have been successfully completed that confirm reservoir simulation modelling projections. If implemented early in the life of a shale oil well, application of these processes can slow the production decline rate, recover far more oil earlier and at lower cost, greatly improve profitability and extend the life of the well by several years, while precluding the need for artificial lift.
Cyclic injection-flowback (huff and puff, HnP) of natural gas or carbon dioxide has been shown to improve the recovery of oil from low permeability, low porosity shale reservoirs. However, natural gas and carbon dioxide are limited in effectiveness and utility; natural gas has a high miscibility pressure and high mobility and hence potential for leak-off and inter-well communication; carbon dioxide is not readily available, is costly, and corrosive. In this study, a novel shale oil HnP EOR process, utilising a liquid solvent comprised of mixtures of propane and butane (C3 and C4), referred to as SuperEORTM (Downey et al, 2021), was evaluated for its efficacy in recovering oil compared to methane and carbon dioxide. The advantages of the propane and butane solvent are its low miscibility pressure with the produced oil, it is injected as a liquid, and is easy to separate and recycle. In this study, an Eagle Ford shale core with produced Eagle Ford oil and a Permian Wolfcamp shale core with produced Wolfcamp oil were investigated. PVT and minimum miscibility tests of the fluids were combined with petrophysical analysis to design laboratory tests and provide metrics for tuning a compositional model. Two Eagle Ford facies were investigated, a calcite/quartz-rich mudstone/siltstone with a porosity of up to 10% and a calcite-rich limestone with porosity ranging from 3% to 6%. At reservoir stress, the matrix permeability averages about 2E-4 md. One facies of the Wolfcamp shale was tested, which is 80% quartz, has a porosity of about 7-11%, and average matrix permeability of 9E-3 md. SuperEOR was carried out on core plugs re-saturated with produced oil for 16 days at reservoir conditions of 5000 psi at 101°C for the Eagle Ford and 79°C for the Wolfcamp. For the Eagle Ford shale, five to 6 HnP cycles using a 1:1 ratio of C3 and C4, at injection pressures of 5000 and 3000 psi, with 20 hours of soaking per cycle, yielded a recovery of 55% to 75% of the original oil in place (OOIP) for the lower porosity facies and over 80% for the higher porosity facies of the Eagle Ford. For the Wolfcamp shale, at an injection pressure of 3000 psi, 85% of the original oil in place was recovered using 1:1 ratio of C3 and C4. In comparison, the Wolfcamp shale, at similar experiment conditions and number of HnP cycles, yielded about 30% of the OOIP when methane was used as an injectant/solvent and yielded 75% of OOIP when carbon dioxide was used. The efficacy of the HnP process on the Eagle Ford shale at the core scale was investigated through reservoir modelling using a general equation-of-state compositional simulator and the results were compared to the laboratory data and a field scale EOR simulation on three horizontal wells using carbon dioxide, methane, and the C3:C4 solvent. The wells had a production rate of <3 bbl/day prior to shut-in and responded poorly to natural gas HnP EOR due to excessive leak-off. The HnP simulations comprise cycling 23 days of injection followed by 30 days of production for 17 years. The recovery utilising methane is 45%, carbon dioxide 72%, and 90% with the C3:C4 solvent for the field simulation, which are generally similar to the laboratory tests and the core simulation.
Over the last decade, tight oil production has become significant with the success of horizontal drilling and hydraulic fracturing. However, the recovery factor of tight oil production remains very low and no standard secondary recovery method exists after primary depletion. We propose a new secondary recovery method: to use existing hydraulic fractures (every other fracture) in a horizontal well as gas injection and oil production sites to conduct inter-fracturegas flooding within a single well. An ideal process of this method envisions a horizontal well centered in an enclosed reservoir, where the hydraulic fractures are evenly distributed along the well, parallel to each other. If the hydraulic fractures can be effectively isolated, and injection and production can be conducted through alternate fractures at the wellbore, then highly efficient flooding patterns can be created. Key questions include: Is there adequate injectivity and productivity in a sub-microdarcy reservoir?How far are the ideal reservoir conditions from reality?How difficult is it to isolate individual fractures within the wellbore? In addressing these key questions, first, the success of a flooding process relies on reasonable injectivity and response time between the injector and producer – in this case the injector being one hydraulic fracture and the producer being an adjacent hydraulic fracture; both economical rates and reasonable communication time between adjacent fractures are demonstrated through analytical calculations and reservoir simulations in a typical well setting; nearly 100% recovery is achieved in the reservoir units between the fractures in a miscible flooding process. Second, actual reservoir conditions are incorporated in our study, focusing on direct fracture communications; the effects are demonstrated, and comparisons among different methods are made. Finally, potential challenges in operations are summarized and current technologies are reviewed; the gaps between the current settings and the required settings are demonstrated. Economic discussions are made, indicating positive scenarios with large tolerances. With the rapid development of tight oil reservoirs, Enhanced Oil Recovery (EOR) technologies are urgently required to improve the recovery factor beyond primary depletion. An effective flooding process may be conducted if the hydraulic fractures can be used as injection and production ports. As a first attempt to envision an inter-fracture flooding process, key aspects are defined and examined, showing promising results. Inter-fracture gas flooding may become a standard secondary recovery technique for tight oil reservoirs and add significant reserves.
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