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In gas condensate reservoirs, production performance is compromised by the liquid dropout due to reservoir pressure depletion below the dew point pressure. In the shale gas-condensate plays, the condensate banking caused by a high pressure drop further reduce the productivity of the well. Evaluation of the condensate banking effect in shale reservo...
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Natural gas is a rapidly growing source of energy, supplying more than a quarter of the global demand for power. Gas condensate is one type of natural gas resources in which liquid drop-out can occur as the pressure decreases throughout the lifetime of the reservoir. This behavior can severely affect the reservoir’s productivity. Chemical and mecha...
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... Various physical mechanisms occur in the subsurface formations during CO 2 injection, for instance, oil viscosity reduction and swelling, capillary entrapment, diffusion, and repressurization (Alfarge et al., 2017;Hawthorne et al., 2013). Recently, many researchers have investigated roles of a range of multi-physics processes during enhanced recovery processes in unconventional reservoirs (Gala and Sharma, 2018;Jia et al., 2017;Kanfar and Clarkson, 2017;Meng et al., 2015;Pankaj et al., 2018;Song and Yang, 2013;Wan et al., 2016;Zhang et al., 2018a,b). Due to the nature of ultralow matrix permeability in these unconventional reservoirs, convection flux is almost irrelevant in the fluid transport from fracture to the matrix (Yu and Sheng, 2016). ...
Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework.
Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well.
The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near-wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.
... Optimum injection pressure of CO 2 huff n puff prosses can be set around the minimum miscible pressure (MMP) between oil and CO 2 , while the soaking time could be optimized for enhancing oil recovery (Song & Yang 2013;Yu et al. 2016). The number of huff n puff injection cycles can also be optimized to improve oil production Meng, et al., 2015). ...
Oil and gas industry is struggling to improve oil production using several methods. CO2 injection is one of the advance proven technology to enhance oil production in numerous oil field in the world. Key parameters during CO2 injection are viscosity reduction and oil swelling which can improve oil production. CO2 injection also has high possibility to be applied in Indonesia's oil fields due to abundant CO2 sources surrounding oil fields. R field is one of reservoir candidates that appropriate for CO2 injection. It has a low pressure and low oil recovery due to low permeability (1-26,2 mD).The CO2 injection technique used in this study was huff and puff that consist of injection, shut in, and production phases. The simulation was conducted using compositional simulator. There were two parameters chosen to be analyzed, which were soaking time and injection cycle. The objective of this study is to know the CO2 huff and puff perfomance for improving oil recovery on low permeability reservoir. The result of the soaking time cases yields optimum condition in 21 days. For the case of injection cycle, the result for optimum condition is in 2 injection cycles. The recovery factor (RF) for both optimum condition reaches 22.96% from the baseline without gas injection (RF 5.82%).
... Of course, for a single cycle, oil recovery will be higher if the soaking time is longer (Gamadi et al., 2014b;Yu et al., 2016a). But the effect of soaking time is less significant in core tests using gas condensate (Meng et al., 2015a(Meng et al., , 2015b. For more results on the subject, see Sheng (2015). ...
In view of the problems of low matrix permeability and low oil recovery in shale reservoirs, CO2 huff and puff technology is considered as an effective method to develop shale oil reservoirs. However, the production behaviors of actual shale reservoirs cannot be reproduced and the EOR potentials cannot be evaluated directly by scaled models in the laboratory. Conventional CO2 huff and puff has problems such as early gas breakthrough and gas channeling leading to inefficient development. In this article, with the help of a three-dimensional experimental simulation apparatus, a new method of CO2 huff and puff with a horizontal well assisted by pumping production and water injection disturbance is developed. The dynamic characteristic, pressure field distribution of soaking and the enhanced oil recovery effect are comprehensively evaluated. The results show that the soaking stage of CO2 huff and puff can be divided into three stages: differential pressure driving, diffusion driving and dissolution driving. According to the pressure field distribution, after water injection disturbance, the fluctuation boundary and distribution of pressure becomes more stable and uniform and the sweep rate is greatly improved. Water injection disturbance realizes the combination of CO2 injection energy enhancement and water injection energy enhancement and the CO2 injection utilization rate is improved. It has the dual effect of stratum energy increase and economic benefit. The new huff and puff method can increase the oil recovery rate by 7.18% and increase the oil–gas replacement rate to 1.2728, which confirms the potential of horizontal well pumping production and water injection disturbance-assisted CO2 huff and puff technology to improve oil recovery.
The condensate gas reservoir with bottom water and oil-rim faces the invasion of oil-rim and bottom water in the process of depleted gas production. In order to explore the invasion mechanism and distribution of oil-rim for a better coping strategy, the long-core displacement apparatus was modified for X-CT scan withstanding high temperature and high pressure (HTHP). From 56.58 to 47 MPa, the oil-gas contact rose fast and gradually slowed down, and the corresponding invasion volume accounted for 82.98% of the total invasion volume. From 47 to 8.8 MPa, the watercut soared to 98% and the invasion rate tended to stagnate. Finally, oil-rim oil was left completely in the reservoir pores and the recovery of condensate oil was only 30.27%. The paper revealed the damage of excessive pressure drop to condensate and oil-rim, and discussed its influencing factors and various pressure control methods. The modified apparatus filled the gap of obtaining oil saturation by X-CT scan under stable HTHP, which had a general application prospect in subsequent optimization and core displacement experiments where oil distribution needed to be observed under HTHP.
Increasing global trend of unconventional production impelled the oil and gas companies to adapt the EOR mothods to unconventionals to increase the recovery. In this study, a deep review of cyclic gas (Natural Gas, CO2, N2) injection processes and the methodology to apply in unconventional shale reservoirs is described by investigating all the geological, petrophysical, production and reservoir engineering aspects. The significance of each uncertainty and control variable throughout the process is outlined.
A full-physics commercial simulator is used to identify the significance of control variables, and also the level of uncertainty which are directly affecting the production and recovery functions. The challenges encountered during implementation of cyclic gas injection processes are outlined in order to provide a comprehensiveand practical implementation perspective rather than only theoretical or a simulation work. Besides, the theory, advantages, drawbacks, benefits are given in details. Results of real cases are being compared and matched with the simulation results.
The study indicates the incremental advantages of appliying huff`n puff process in unconventional shale reservoirs by comparing the primary production performance with the performances of cyclic injection cases that uses various gases. Key factors that directly affect the reservoir, completion and operational attitudes are circumstantially given to technically handle a successful project in a feasible way. In the model, the objective function is built by considering the economic parameters to help NPV maximization in a realistic perspective. S-curves and tornado charts is used to visualize the results and illustrate the significance of parameters and ranges of the developed probabilistic economic model. The effect of huff`n puff method and how a successful cyclic injection gives better recovery and feasibility results is clearly shown.
Petroleum literature includes several studies related to cyclic gas injection. However, these works are either only focus on the simulation/theoretical parts or only includes a case study that focuses reservoir/production analysis. This comprehensive study closes the gap aims to be a reference by including a deep look into details of the theory and combines it with real field cases and solutions by clearly describing the candidate selection, modeling, physical parameters/key factors, economics, and success stories.
Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.
Primary oil recovery from fractured unconventional formations, such as shale or tight sands, is typically less than 10%. The development of an economically viable enhanced oil recovery (EOR) technique applicable to unconventional liquid reservoirs (ULRs) would lead to tremendous increases in domestic oil production. Although injection techniques such as waterflooding and CO2 EOR have proven profitable in conventional formations for decades, EOR in ULRs presents a far more difficult challenge. The extremely low permeability and mixed wettability of unconventional formations are the foremost obstacles to success. Because of the challenges associated with water-based EOR techniques (a.k.a. chemical EOR) in shale, several non-aqueous injection fluids have been considered, including CO2, natural gas and (to a lesser degree) nitrogen. All these fluids have significantly lower viscosities than water, allowing them to more easily penetrate shale nanopores. Unlike water, they also each possess some degree of miscibility with oil, which enables the gas to extract oil through a combination of mechanisms. Based on laboratory-scale experimentation, CO2 and rich natural gas (methane-rich natural gas containing high concentrations of ethane, propane and butane) are the most promising EOR fluids. The interpretation of results from field tests in the Bakken and Eagle Ford Formations have been complicated by interference of frac-hits or well-bashing caused by hydraulic fracturing at nearby wells. In this review we cover mechanisms, laboratory experiments, numerical simulations and field tests involving high-pressure CO2, natural gas, ethane, nitrogen and water.
With the help of large-scale physical simulation experiment technology, the physical simulation experiments of the CO2 huff–n-puff with the staged-fracturing horizontal well could be acheived. We studied the production process of CO2 huff–n–puff and influence of different parameters affect oil recovery during the CO2 huff-n-puff procedure, ultimately, the operation parameters were optimized by numerical simulation. The results show that CO2 can quickly enter the deep formation through the horizontal well and the fracture during the huff period and staged-fracturing horizontal well can greatly increase the contact area between CO2 and crude oil, which improves the efficiency of extraction, dissolution, reduction of viscosity between CO2 and crude oil. During the puff period, the horizontal well and fractures can reduce the flow resistance effectively, so as to improve the flow capacity of crude oil. After 3 cycles of CO2 huff and puff, the oil recovery can be enhanced by 11.13%~21.39% compared with that obtained by elastic flooding, which indicates that the exploitation method of CO2 huff–n–puff can improve the development effects of tight oil reservoirs. CO2 huff-n-puff injection parameters are optimized, the results show that the optimum time of injection is 1 year, the optimum soaking time is 30d, and the optimal injection pore volume is 0.18HCPV. This research can provide a certain technical support for effective development of tight oil reservoirs.
