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.
This paper presents a scoping study to investigate the economic viability of nitrogen injection to improve the recovery of coalbed gas. The sensitivity of the analysis to key reservoir parameters is also presented. The results of the study suggest that nitrogen injection may be more attractive than conventional pressure depletion for lower permeability formations where the loss in permeability with pressure decline is significant. Nitrogen injection economics are shown to be very sensitive to the costs associated with injection and separation and are adversely affected by reservoir heterogeneity. Introduction Conventional pressure depletion methods for the recovery of coalbed methane are inefficient with ultimate recoveries generally not exceeding 50% of the initially sorbed gas volume. This has led to an increasing interest in enhanced recovery processes using nitrogen and carbon dioxide injection. Puri and Yee report modelling studies which suggest that both the rate of methane recovery and ultimate recovery are significantly increased by the injection of nitrogen. However, the improved methane recovery is accompanied by increased costs associated with the supply of nitrogen and the need to separate the produced gas stream as a result of early nitrogen breakthrough at production wells. Although Puri and Yee suggest that the economic benefits of nitrogen injection more than offset the nitrogen injection and separation costs, they provide no details of their economic evaluation and no indication of the sensitivity of project economics to the high levels of uncertainty in estimating important reservoir parameters such as permeability, reservoir heterogeneity, gas-water relative permeability and the stress dependence of cleat permeability and porosity. Their study assumed a homogeneous seam, core measured relative permeabilities and constant rock properties. These assumptions largely determine the production characteristics of the seam - methane and water production rates and nitrogen breakthrough - and therefore determine the economic viability of the process. There exists a clear need for a parametric study to investigate the effect of reservoir properties on the economic viability of nitrogen injection which utilises more realistic predictions of potential field performance. The purpose of the present paper is to present the results of a preliminary economic evaluation of the nitrogen injection process for potential application to the Fruitland Formation in the San Juan basin. This particular formation was chosen both because it is the focus of considerable development activity and because it has been the subject of numerous recent studies to evaluate reservoir properties. The sensitivity of nitrogen injection economics to key reservoir parameters is demonstrated on the basis of reservoir simulations using a three-dimensional, two-phase, dual porosity, fully compositional numerical code which models multicomponent sorption in a thermodynamically consistent manner. Reservoir Description The reservoir data used in this study is similar to that for the Cedar Hill field in the Fruitland formation of the San Juan basin. The data used is summarised in Table 1. P. 627^
Oil production via horizontal wells with multistage fracture stimulation treatment completions in the Bakken shale of North Dakota and Montana began in 2003. Since then, over 19,000 Bakken shale horizontal wells have been completed and placed into production. Oil production from horizontal Bakken shale oil wells peaked in November 2019 at 1.5 million barrels/day, and is at about 1.2 million barrels/day as of September, 2022 (EIA). There have been several shale oil EOR tests conducted over the last several years, involving the injection of water, CO2 and natural gas. This paper builds upon shale EOR modeling work described in a 2019 NETL report. In that report, a compositional simulation model of the Bakken was constructed, and a production history match on primary oil, gas and water production from a group of wells was obtained. The match model was then used to evaluate the enhanced oil recovery via cyclic injection of CO2, dry gas, and wet gas. This paper utilizes some data from that report to assess two novel, proprietary shale oil EOR processes in the Bakken, in the same area of the Williston Basin. The paper illustrates how these proprietary shale oil EOR processes may be implemented at lower BHP to mitigate interwell communication, while enabling greater oil recovery than via injection of water, CO2 or natural gas. Compositional reservoir simulation modeling of the two novel EOR processes in the modeled Bakken shale wells indicates potential incremental oil recoveries of 200% and 300% of primary EUR may be achieved. The two novel shale oil EOR methods utilize a triplex pump to inject a liquid solvent having a specific composition into the shale oil reservoir, and a method to recover the injectant at the surface, for storage and reinjection. One of the processes enables further enhanced oil recovery via cyclic fracture stimulation at the start of the EOR process. The processes are fully integrated with compositional reservoir simulation to optimize the recovery of residual oil during each injection and production cycle. The patent pending shale oil EOR processes have numerous advantages over cyclic gas injection - shorter injection time, longer production time, smaller, lower cost injection volumes, no gas containment issue - much lower risk of interwell communication, elimination of the need to buy and sell injectant during each cycle, much better economics, scalability, faster implementation, optimization via integration with compositional reservoir simulation modeling, and lower emissions. If implemented early in the well life, their application may preclude the need for artificial lift, to produce more oil sooner, resulting in a shallower decline rate and higher reserves.
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