Evaluation of Cyclic Gas Injection in Enhanced Recovery from Unconventional Light Oil Reservoirs: Effect of Gas Type and Fracture Spacing
Production from ultra-low permeability shale plays requires advanced technologies such as horizontal wells with multistage hydraulic fracturing treatment. In this study, a cyclic gas injection method with two pumping schedules is introduced as an enhanced oil recovery (EOR) method. Fracture spacing and type of injection gas in a horizontal well from the Bakken formation are analyzed through numerical simulations.
The economic profitability and reservoir performance are also investigated. Rate transient analysis is used to anticipate hydraulic fracture and effective fracture permeability. Different fracture spacings are selected as the major determinant factor in generating an effective reservoir contact area. Compositional simulations are conducted to model incremental oil recovery after cyclic injection of three gases (ethane, CO2, and natural gas). Economic indicators of net present value (NPV), internal rate of return (IRR) and oil recovery factor are compared to determine the best alternative among the proposed investment scenarios. Current market and a certain time-frame (2015–2035) are used to assess the investment viability of unconventional oil plays.
Cyclical injection of ethane and CO2, remarkably improved oil recovery from the Bakken example. Natural gas injection however, led to inferior results and in terms of investment, may not guarantee the long-term success. Some scenarios are identified as profitable for high oil-API but do not achieve positive outcomes from lower oil specific gravities. The results from this study highlight the impact of fracture spacing in incremental oil recovery. Producing a majority of the cumulative oil during the first years makes most of the scenarios viable only for short terms. To maintain the long-term cost-effectiveness, performing cyclic gas injection through hydraulic fractures is recommended.
Cycle sizes directly impact the propagation of injectant and the extent of the drainage area. Increasing the number of fracking stages can be an alternative strategy to gas injection in reservoirs with lower oil-API.
Bakken, an enormous liquid-rich shale resource and its adjoining formation of Three Forks, extending from North Dakota, Montana, and South Dakota in the United States, to Saskatchewan and Manitoba in Canada, has made strong contributions to oil production in North America. According to the 2013 United States Geological Survey (USGS) project reports, there are 7.4 billion barrels of unrecovered oil that can be produced from the Bakken and Three Forks formations . The U.S Energy Information Administration (EIA) also estimates that the Canadian portion of the Bakken reservoir contains 1.6 billion barrels of oil and 2.2 trillion cubic feet of natural gas . Unconventional reservoirs are difficult to extract due to their restrictive economics and substantial needs for special completion techniques.
Extremely low permeability in unconventional reservoirs prevents oil from flowing naturally into the wellbore. The ultra-low (micro- to nano-Darcy) matrix permeability makes the aforementioned resources geologically unfavorable for recovery. In contrast, the low viscosity and high compressibility of hydrocarbon fluids make them viable potential options for oil production.
The advents of innovations in horizontal drilling and hydraulic fracturing has led the industry to be able to access significant amounts of hydrocarbons in the United States, which were previously considered as unattainable resources. Hydraulic fracturing is the high-pressure injection of a fracking fluid (water, chemical additives to control water viscosity, and proppants) into a horizontal well, at predetermined distances. The pressure creates fractures, which are kept open by proppants providing conductive paths for fluid flow . Hydraulic fracking has provided massively enhanced production in the United States. According to the EIA drilling productivity report for tight oil, total production from the Bakken region has shown a steady growth since 2009 and reached from 200,000 to 1,200,000 barrels per day in 2018 because of the mentioned technologies .
However, unconventional oil extraction utilizing fracking methods is accompanied by economic and sometimes technical challenges. In hydraulic fractured wells, by virtue of the conductive paths for fluid flow, high initial production rates and consequently very steep decline rates occur within the early life of the reservoir. Implementing proper EOR methods is required to overcome the quickly flattened recovery and to maintain production levels in unconventional resources.
Secondary and tertiary recovery mechanisms are sought to increase the oil production through pressure maintenance and displacement mechanisms. CO2 injection, as the second most common EOR method after thermal recoveries for heavy oil , has been successfully employed in light to medium oil reservoirs [6,7,8,9,10,11]. However, low permeability and limited injectivity in tight shale reservoirs yield poor gas displacement efficiencies since the injected fluid would take a very long time to spread from the injector towards the producer.
Moreover, because of high degree of heterogeneity in unconventional resources, injectors and producers may not have effective connections for fluid flow. The huff-n-puff method in which the gas injection and oil production are performed in a single well, has made efficient enhanced recovery from tight formations viable. In this method, a gas (e.g., CO2) is injected into the well for a certain period. After that, the well is shut-in and a soaking time is started. The mechanisms involved in CO2 EOR consist of an increase in average reservoir pressure, oil swelling, and vaporization of light and medium hydrocarbon components, oil viscosity reduction and enhanced oil mobility .
Molecular diffusion of CO2 in the oil phase also plays a key role in this process. After the soaking period, the well is put into production for a specific time and the whole procedure is repeated. Simulations of the cyclic CO2-injection method in Bakken have demonstrated incremental  oil recoveries between 5% to 20% in multistage hydraulically fractured wells . Results from CO2 extraction experiments on Upper and Lower Bakken core plugs also indicated that CO2 diffusion under miscible conditions lowers the oil viscosity and makes the oil extraction from tight cores feasible . Thus, the Bakken formation could be considered as a promising candidate for cyclic CO2 injection EOR.
In addition, due to huge potential of this EOR method in secure storage of CO2, much attention has been paid to various designs of CO2 EOR in previous years. In North America, available and low-cost supplies of CO2 in addition to vast pipeline networks have led to successful CO2-EOR projects including the Wasson field in U.S. and Weyburn in Canada [16,17,18].
A successful oil extraction may be affected by many factors such as accessibility of the injection gas, gas price and the investment circumstances. Although promising recovery results from CO2 injection are obtained, there are some limitations, which are significant controlling factors in EOR projects. Severe corrosion of pipelines, wellhead valves and surface facilities is a challenging issue that usually occurs in CO2 injection techniques.
Simulation studies have investigated the possibility of using different injection gases for the purpose of shale EOR. Recovery of 6.5% was obtained from natural depletion and 29% incremental oil recovery was observed after cyclic injection of a mixture of 77% C1, 20% C2, and 3% C6 into a hydraulic fractured well in a shale oil reservoir . The obtained oil recovery from CO2 huff-n-puff into a shale condensate field was slightly higher than methane injection while both greatly outperformed nitrogen injection . Enhanced recovery potential of injecting nitrogen, methane, ethane and CO2 into shale oil reservoirs has been also investigated through numerical modelling by Li et al. . Ethane has shown great ability in enhancing oil recovery by 15.17%, followed by 9.74% from CO2 injection, 7.52% from methane injection and 6% from N2 injection. The lower minimum miscibility pressure (MMP) of CO2 compared to other gases, including methane and nitrogen, has made it favourable for most of the reservoirs since there is no need for high injection pressure .
A profitable cyclic gas injection (CGI)-EOR process is reliant on the availability of sources of the injection gas. In the fields where the available low-cost natural CO2 resource is not sufficient and other sources of CO2 such as coal-fired power plants are not economically profitable, miscible or immiscible hydrocarbon gas injection is an alternative technique. In our previous study, we have investigated various uncertainties incorporated in a cyclic CO2 injection project in the Bakken formation .
An experimental design method coupled with numerical modelling were used to introduce the parameters controlling hydrocarbon recovery factor, CO2 utilization factor, and CO2 retention factor. Hydraulic fracture half length, fracture spacing, rock permeability, formation porosity, injection pressure, start time of injection and pay zone thickness are the parameters affecting the project’s profits. Different studies also proposed useful methods and algorithms of phase field model for fracture in poroelastic media . The economic profitability and viability of recovery enhancement by hydrocarbon gas injection have been widely investigated and confirmed through simulation studies as well as field operations. Natural gas, methane enriched with C2, C3, C4 or mixtures of CO2 with C1, C2, C3 are examples of injectants used in EOR projects including North Slope and Prudhoe Bay field . In the latter, CO2 acts as a carrier gas and miscibility is achieved between oil and C3 and C4. The reported West Sak oil (18.5° API) viscosity reduction by ethane was effectively higher than CO2, followed by C1 . In another study on West Sak crude oil, miscibility of ethane was observed in lower pressures of around 600 psi while CO2 miscibility was not achieved even at 6,600 psi .
The higher critical pressure of CO2 compared with ethane, increases its liquefaction pressure. Hence, achievement of liquid state of CO2 under reservoir conditions (to make it miscible with crude oil) requires higher injection pressure. The non-corrosiveness of ethane and natural gas also minimizes the damage coming from CO2 acidity and consequent corrosion problems . Moreover, the lower miscibility of hydrocarbon gases in water compared with CO2, reduces the possibility of gas solution trapping in reservoir brine and consequently a higher gas utilization factor.
However, the relatively higher price of ethane and natural gas compared with CO2 necessitates further economic analysis to see if utilizing hydrocarbon gases instead of CO2 can lead to economically sound projects [29,30]. Therefore, it is vital to examine the potential of other injection gases in incremental oil recovery. To do that, accurate field scale simulation is required in order to evaluate the reservoir performance after cyclic gas injection EOR technique using different gases. In this study, using an integrated analytical-numerical method, a reservoir dynamic model is constructed. We designed a CO2-EOR scheme based on the fixed and growing-cycle sizes of gas injection and oil production. Then an economical decision-based approach is followed to study the effect of stage numbers, gas type and injection schedule on the EOR project economics.
The objective of this study is to deploy different cyclic gas injection scenarios with various fracture spacings to evaluate the potential of different designs of CGI for EOR in the Bakken formation. First, reservoir properties are estimated using analytical modelling. The compositional reservoir dynamic model is then constructed using CMG-GEM software. After history matching, production forecasting is performed in different scenarios to be able to choose the best scenario from both the economical and technical points of view. Two schemes of cyclic gas injection with fixed and growing cycle size are introduced to improve the lateral continuity of injected gas at various fracture spacing.
Three injection gases—CO2, ethane (C2H6) and natural gas (NG, a mixture of 75% methane and 25% ethane)—are utilized in our the model. The current study will strive to optimize the asset value for the operators, investors and decision makers by identifying the technically and economically optimum opportunities to maximize production and recovery from other unconventional reservoirs with similar properties.
Four main scenarios proposed in this study are natural depletion, CO2 injection, ethane injection and natural gas injection. Each scenario uses currently available gas price and oil price data from 2014 through 2019 and forecast data since 2019 to 2035. To examine how the variations in fracking costs, oil price and gas price will affect the ultimate cash flow, a sensitivity analysis is conducted.
Details of rate transient analysis (RTA) calculations are described in our previous work . The calculated hydraulic fracture permeability (10.8 md) and effective fracture permeability (0.02 md) obtained from an analytical model based on flow regimes in horizontal wellbores are used as an initial estimate for history matching in the numerical model. We use production data from the Bakken well to construct a numerical reservoir model. A dual porosity medium defines the natural fractures. Local grid refinement (LGR) is applied in I and J directions within the matrix and fracture blocks near the hydraulic fractures.
Hydraulic fracture blocks width (Whf) is set to 1 ft. Length of stimulated reservoir volume (SRV) is set equal to fracture length of 450 ft and SRV width equals fracture spacing of 300 ft. Effective fracture permeability kfeff of 0.002 mD and matrix permeability kmeff of 0.0008 mD are found through history matching. SRV and USRV properties of reservoir and fracture are listed in Figure 1. The detailed procedure and results of history matching are reported in our previous publication .
Figure 1. Schematic of two hydraulic fractures (HF) and SRV area with local grid refinement. SRV length is 450 ft. SRV width is variable; depending on fracture spacing.
Design of Cyclic Gas Injection
The main mechanism of oil mobilization in unconventional tight resources is known as molecular diffusion of injection gas in oil phase. Miscibility is achieved through multiple contacts and mass transfer between injection gases and crude oil components through vaporization/condensation. Reduced IFT between oil and injection gas leads to oil swelling and viscosity reduction which are the main mechanisms of gas injection EOR . Injection pressures of 5000 psi are used to achieve miscibility.
The molecular diffusion coefficients of CO2, ethane and natural gas used in this model are set to 5.5 × 10−4, 4 × 10−4 and 6 × 10−4 cm2/s, respectively [13,14]. As mentioned, in the field scale studies of cyclic gas injection process, normally the operation continues for a certain number of fixed-size cycles. However, in our simulation, we investigate and impose proper constraints to adopt a varying cycle size design as outlined below. Fracture spacing is an important factor which defines the extent of drainage area and the potential for improved oil recovery.
In tight formation developments, in addition to recovery forecasts, the environmental effects and drilling costs of fracking stages must be taken into account. Reservoir contact area can be improved by identifying proper fracture spacing as well as pumping schedules. Stimulated area and effective fracture half-length in horizontal wells determine the extent of injection gas in the reservoir. In most field scale simulations constant duration for both injection and production cycles are used for cyclic-injection process design.
However, in this study, we adopted a variable cycle size where the injection cycle are continuously increased to fill the previously depleted reservoir volumes. To obtain larger lateral gas continuity between hydraulic fractures longer cycles are utilized in wider fracture spacing. The injection and production lengths for each cycle are selected depending on the fracture spacing. For wider spacings, cycle sizes are extended while for narrow spacing smaller cycles are used.
In the fixed cycle scheme, the well produces under the natural depletion for 150 months and then a cyclic gas injection scheme is applied for total of 270 months. In the later cycles, larger volumes of the reservoir are being drained and more gas is needed to fill the depleted sections. Hence, in an extended cycle scheme the injection duration is increased at the constant injection pressure in order to provide larger volume of solvent. Production cycles are also extended at later cycles as the drainage area in the reservoir is extended. In this design, the soaking intervals are kept constant and injection and production cycle sizes are growing as listed in Table 1.
Table 1. Injection and Production Cycle Sizes.
Results from oil production simulation of each fracture spacing just before start of CGI are shown in Figure 2. The difference in produced oil disappears for more than n = 20 hydraulic fracture stages. At the same time one can conclude that 15 fracking stages giving RF = 16.56% is not significantly different from higher stage numbers of 20 to 40 with recoveries of 17.27% to 17.39%, respectively. However, 10 fracking stages leads to the least recovery of 13.68% due to insufficient drainage volume around each hydraulic fracture.
Figure 2. Primary (natural depletion) recovery factor at different number of fracture stages.
Figure 3 and Figure 4 show the average reservoir pressure (dashed lines) and oil recovery factor (solid lines) during CGI in both fixed and growing cycle sizes for n = 10 and n = 35. As shown, the extended cycles are capable of maintaining the average reservoir pressure effectively higher than that obtained from fixed cycles. This allows for extension of the injection zone and more efficient diffusion between CO2 and oil.
As a result, the oil recovery factor in FS = 10 is improved from 15.8% to 17.7% and in FS = 35 it is slightly changed from 28.6% to 29.09%. The more number of fracture stages, the less changes between two injection schedules are observed. The reason is more effective depletion of SRV in any type of injection. However, with less number of fractures, extended cycles lead to higher oil recovery. This method can provide enough time for the injected gas to penetrate into the reservoir and contact the in-situ oil.
Figure 3. Dashed lines: average reservoir pressure; solid lines: oil recovery factor during CGI in both fixed and growing cycle sizes for n = 10.
Figure 4. Dashed lines: average reservoir pressure; solid lines: oil recovery factor during CGI in both fixed and growing cycle sizes for n = 35.