Day 3 Wed, June 08, 2022最新文献

{"title":"A Brief Summary of Seventy Years of Well Test Analysis","authors":"A. Gringarten","doi":"10.2118/209629-ms","DOIUrl":"https://doi.org/10.2118/209629-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Transient well test analysis has been used to assess well condition and obtain reservoir parameters for over seventy years. At a time when Machine Learning (ML) and Artificial Intelligence (AI) are coming-of-age and may eventually replace well test interpreters, it is worth taking stock of the progress made in well test analysis since the major initial publications of the early 1950's.\u0000 \u0000 \u0000 \u0000 Major improvements in well test analysis since the early 1950's have occurred approximately 13 to 19 years apart, driven by the availability of both new types of data and new mathematical tools. Using a computer-generated data set of pressure and rate, we illustrate the evolution of well test analysis over the years: straight line methods of the early 1950's; log-log pressure plots of the late 1960's and early 1970's; formulation of an integrated methodology in the early 1980s; introduction of pressure-derivative analysis in 1983; derivation of a stable deconvolution algorithm in the early 2000's; and its current, successful extension to multiple interfering wells.\u0000 \u0000 \u0000 \u0000 Over the last seventy years, well test analysis has moved from just estimating well performance to becoming a very powerful tool for reservoir characterization.\u0000 \u0000 \u0000 \u0000 Although the development of commercial software has been a factor in making practicing engineers aware of these improvements, acceptance has been slow: deconvolution has been developed twenty years ago and has been included in commercial software for the last fifteen years, yet is still not used in routine well test analysis. In addition, interest in well test analysis seems to be fading, which is in sharp contrast with its popularity in 1970's, as measured by the attendance to the well test analysis sessions in the annual ATCE meetings. It is hoped that the new advances in ML and AI will reverse this trend and reinstate well test analysis as a major reservoir characterization tool.\u0000","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125744221","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Stimulation of Conventional Geothermal Wells with Propped Fractures","authors":"J. Shaoul, Jason Park, C. (. de Pater","doi":"10.2118/209631-ms","DOIUrl":"https://doi.org/10.2118/209631-ms","url":null,"abstract":"\u0000 Conventional hydrothermal (\"low enthalpy\") geothermal reservoirs are already being developed in the Netherlands as a source of heat for greenhouses, district heating. Many of these wells are left with a positive skin after being drilled, and could therefore benefit from stimulation. In order to evaluate the potential benefit of propped fracture stimulation for this type of reservoir, a history match of a real geothermal injection and production doublet was made using an industry standard 3D reservoir simulation model. This model was then used to perform production and injection forecasts for different completion scenarios, including propped fracturing.\u0000 All available data (logs, PLT, welltests) was used in creating and history matching the reservoir simulation model. The model was history matched to the individual welltests for both the production and injection well and to a 3 year data set of production and injection data. In order to match the long-term pressure trend, an increase in the size of the thermal fracture in the injection well was needed. The history matching results were compared to the predicted increase in the size of the thermal fracture using a new 3D FEM fracture model. The same model parameters were also used to design propped hydraulic fracturing treatments. The propped fractures were also placed in the reservoir simulation model for both the production and injection wells, to predict the performance of the wells with fracture stimulation.\u0000 Although the actual wells used in this study had negative skins to begin with (after drilling), many wells drilled in the same reservoir (Rotliegend in the Netherlands) have positive skins to begin with. Our simulations showed significant improvement in well injectivity and productivity using propped fractures, compared to a well with a typical initial skin of +2 seen in new open-hole wells in this reservoir. Injection pressure was also reduced significantly, to below the regulatory limits on \"safe\" injection. The new 3D FEM model showed that injection well thermal fracture propagation was strongly affected by small differences in the Young's modulus between the higher and lower porosity layers in the reservoir.\u0000 This paper shows, based on actual well data from a real geothermal doublet, the expected benefit from hydraulic fracture stimulation is significant, especially when the wells have a positive skin after drilling. The effect of small differences in rock stiffness on thermal fracture propagation in a geothermal injection well is also a new and surprising result.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134621461","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental and Modeling Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs","authors":"Wuchao Wang, Huiqing Liu, Xiaohu Dong, Zhangxin Chen, Yu Li, Lei Sun, Farong Yang","doi":"10.2118/209713-ms","DOIUrl":"https://doi.org/10.2118/209713-ms","url":null,"abstract":"\u0000 The mixing/interaction between injected gas and remaining reservoir fluid is yet to be extensively understood and the inability to optimize the recovery process has led to limited pilot trials. Therefore, adequate phase and flow behavior analyses and modeling are necessary to better evaluate reservoir performance under CO2 injection to make an informed decision.\u0000 In this work, the phase behavior, and the minimum miscible pressure (MMP) have been experimentally conducted to determine the level of CO2/gas-condensate interaction, including condensing/mixing/vaporizing mechanisms. Moreover, the unsteady-state flow tests were conducted to study flowing characteristics and performance. Based on these studies, the CO2 injection numerical model was constructed using a component model reservoir simulator (GEM) to simulate the effects of injection rate, injection pressure, and injection volume on gas/condensate recovery and CO2 storage. Finally, the stability of CO2 storage was evaluated using numerical simulation of the reservoir.\u0000 The results were analyzed and found that the phenomenon of \"critical opalescence\" occurred when a certain proportion of CO2 was injected into the residual condensate oil and gas system, which meant that CO2 and condensate were mixed as one phase. Factors such as injection pressure, injection rate, and injection volume have a very important influence on the degree of condensate recovery. Only considering the influence of single factor conditions, the higher the injection pressure or gas injection volume or injection rate, the higher the degree of condensate recovery and the greater the potential of CO2 storage. However, based on comprehensive consideration of oil displacement rate and gas channelization, reasonable gas injection speed, injection volume, and injection pressure were finally optimized and screened out as 7000 m3 /day, 0.43 HCPV, and 32 MPa, respectively. The formation pressure was almost constant from 80 years to 130 years, which indicated that CO2 can be deposited stably.\u0000 The study bridges the gap between the extent of CO2/gas-condensate interaction at pressures below the dew point pressure and conflicting reports on this trend. This paper also provides a better knowledge of the governing mechanisms during CO2 injection, which are required for designing suitable CO2 flooding injection for reservoir engineering applications.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116722614","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Temperature Specifications for CCUS Completions Equipment: Steady-State and Transient Thermal Simulations","authors":"Adam Vasper, Ingvild Bakke Fagereng","doi":"10.2118/209637-ms","DOIUrl":"https://doi.org/10.2118/209637-ms","url":null,"abstract":"\u0000 Different simulated injection scenarios can significantly cool carbon capture utilization and storage (CCUS)wells. Cases representing different scenarios were modeled to help determine appropriate temperature specifications for completions equipment in CCUS wells.\u0000 Depleted reservoirs, in particular gas reservoirs, will not support a static column of liquid or dense-phase CO2 to surface at the initial reservoir pressure. During injection, unless there is significant friction or backpressure, the upper part of the well will be at low pressure, with CO2 in the gas phase. Injected, liquid CO2 will depressurize across the wellhead choke, or the upper tubing, resulting in significant cooling as the saturation curve is reached and the CO2 starts flashing. For steady-state injection across a narrow range of rates, a tapered or narrow completion string can be designed that provides sufficient friction pressure to keep the CO2 in the liquid phase. A portfolio or set of wells, potentially with different tubing sizes, will give more flexibility for managing injection rates.\u0000 Transient scenarios such as injection startup or shutdown cause rapid changes in rate and can consequently induce severe thermal shocks. These cannot be completely prevented using only friction or passive downhole devices. Many completion options have been proposed to provide flexibility for injection rate changes and/or reservoir pressure increases. These include concentric or dual strings providing multiple flow paths with different flow areas and hence friction, downhole passive chokes, backpressure control valves, surface-operated downhole flow control valves, and various combinations of these and other technologies. Currently, the only methods to eliminate all the scenarios consideredmay be (active) backpressure control and surface-controlled downhole flow control valves. Whereas the transient effects are most severe in depleted reservoirs, they are also shown to occur in reservoirs approaching hydrostatic pressure.\u0000 The most important component in the completion string is arguably the subsurface safety valve (SSSV). API 14B specifies a maximum leak rate for the closed SSSV. Following a blowout or depressurization event, a leak of high-pressure, liquid CO2 from below the SSSV to low-pressure, gas-phase CO2 above will cause localized cooling at the SSSV, in addition to that caused by the initial depressurization condition. Modeling included simulations of blowout and subsequent SSSV leakage phases for different periods of injection and hence reservoir cooldown.\u0000 To quantify these effects, the work considered temperatures in the different radial sections of the well versus time and depth. Sensitivities on annulus fluid, reservoir properties including pressure and permeability, the rate of mass transfer between phases, and other variables were also investigated. Modeling was performed using a commercial dynamic multiphase flow simulator.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"7 2","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121005585","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Early- and Late-Time Prediction of Counter-Current Spontaneous Imbibition and Estimation of the Capillary Diffusion Coefficient","authors":"P. Andersen","doi":"10.2118/209668-ms","DOIUrl":"https://doi.org/10.2118/209668-ms","url":null,"abstract":"\u0000 Solutions are presented to predict 1D counter-current spontaneous imbibition oil recovery at early and late times, i.e. before and after the imbibing water reaches the noflow boundary based on knowing the capillary diffusion coefficient. The system is presented in a normalized form where the space, time and saturation variables are scaled. The normalized capillary diffusion coefficient (NCDC) has an area of 1 when integrated over the saturation range with positive capillary pressure (where spontaneous imbibition occurs). The scaled solution of the system hence only depends on the shape of the NCDC function and not its magnitude (which by definition has an area of 1).\u0000 Based on the semi-analytical solution by McWhorter and Sunada (1990) scaled recovery equals the square root of scaled time for early times. The time scale depends on one part τ related to known constants, and a part Tch related to the NCDC shape. The normalized critical time Tn,cr when the square root regime ends is known exactly from this solution. Recovery thereafter depends on the NCDC and must be calculated numerically.\u0000 A dataset is generated based on combining 1000 sets of relative permeabilities and capillary pressure functions with mixed-wet to strongly water-wet states and end point mobility ratios into corresponding NCDCs. Recovery is studied in terms of how long the early square root of time behavior lasts, what the imbibition rate coefficient is in that period, and how recovery changes at late time. The former lasts longer than Tn,cr in practice and is instead characterized by a transition time Tn,tr. The parameters Tch, Tn,tr are well correlated with the CDNC shape, as quantified by one or two fractions zα,β denoting the fraction of the NCDC between normalized saturations α and β. Late time recovery was modeled using an extended Arps type decline curve where one parameter r was correlated with zα,β. We thus find relations between the shape of the NCDC and the behavior of the solution at early and late times.\u0000 Next we interpret recovery data to estimate the absolute capillary diffusion coefficient. This is done by systematically determining RFtr and the Arps parameter from tuning or type curves and linking them to associated NCDC fractions zα,β. The methods are illustrated using literature experimental data. The predicted NCDCs could predict the original recovery curves. It was found that systems with high non-wetting phase mobility and strong water-wetness are likely to have most of the recovery occur as proportional to the square root of time.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128684562","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study on Blockage and Fluid Diversion Behaviors of Polymer Microspheres","authors":"Dejun Wu, Yongsheng Liu, Xuejiao Lu, Jian Hou, Kang Zhou, B. Wei, Qingjun Du, Z. An, Haoyu Zheng","doi":"10.2118/209706-ms","DOIUrl":"https://doi.org/10.2118/209706-ms","url":null,"abstract":"\u0000 Polymer microsphere (PM) flooding is a deep fluid diversion technology that is suitable for high water-cut oilfields to further enhance oil recovery. It has been successfully applied in some oilfields in China. However, the flow characteristics of polymer microspheres in porous media are very complex, involving blockage, elastic deformation, and remigration. On this account, we used microfluidic tests and core flow experiments to investigate how polymer microspheres block pore throats and promote fluid diversion.\u0000 Two types of microfluidic chips are first used to study the flow behaviors of polymer microspheres at the pore scale. The blockage and migration behaviors are observed through a single microchannel, and the real-time inlet pressure is monitored by a precision pressure sensor. To explore how polymer microspheres divert fluid, the unequal-diameter dual microchannel model tests are carried out. On this basis, the capacity of polymer microspheres to adjust the shunt flow in high and low permeable cores was investigated by a parallel sand-packed pipe flow experiment from a macroscopic level.\u0000 The results of the single microchannel model tests show that when the particle size of the polymer microspheres is smaller than the inner diameter of the microchannel, the microspheres can freely pass through the microchannel. When the particle size of the microspheres is larger than the inner diameter of the microchannel, the microspheres may first be blocked in the microchannel, and then deform and migrate through the microchannel; correspondingly, the inlet pressure first increases and then decreases. When multiple large-sized microspheres are bridging and blocking the microchannel, it may be difficult for the microspheres to enter and pass through the microchannel, and the inlet pressure shows a rising trend. The results of dual microchannel model tests show that the polymer microspheres can divert flow direction by alternately blocking wide and narrow microchannels. The results of the parallel sand-packed pipe shunt flow experiment show that the polymer microspheres can cause fluid diversion by blocking high permeable cores so that more subsequent fluid can enter the low permeable cores. The variation of the shunt flow rates in the two sand-packed pipes directly reflects the fluid diversion capacity of polymer microspheres from a macro perspective.\u0000 Polymer microspheres flooding breaks the shackles of the traditional idea of using homogeneous displacing fluid to increase oil recovery. As a novel aspect, this paper further interprets how polymer microspheres block pore throats and promote fluid diversion, which is the key mechanism for enhanced oil recovery of this heterogeneous particle suspension.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"74 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127485000","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Improved Initialization of Non-Linear Solvers in Numerical Simulation of Flow in Porous Media with a Deep Learning Approach","authors":"J. Abbasi, P. Andersen","doi":"10.2118/209667-ms","DOIUrl":"https://doi.org/10.2118/209667-ms","url":null,"abstract":"\u0000 Partial Differential Equations (PDEs) have a wide list of applications in modeling complex processes including flow in porous materials. Solution of these equations that are mostly highly non-linear is generally possible using numerical algorithms that are carried out by iterative approaches like Newton's method, where the calculations to find the solution at a new time step are started using an initial guess of the unknown variables. The computational efficiency of the calculations is highly dependent on the closeness of these initial guesses to the exact values. As a routine, solvers pick the solutions at the previous timestep as the kickoff point for Newton's method. Improvement of this starting point at each time step can reduce the time-to-solution of the solver. This study focuses on using a Deep Learning (DL) algorithm for optimization of a PDE solver and improvement of the computational efficiency of simulation of flow in porous media by providing more efficient initial guesses for the unknown variables.\u0000 In this work, a 1D gravity-capillary driven two-phase flow problem with a fully implicit Newton's solver was hired as the base numerical model. A fully connected neural network (NN) was initialized and added to the numerical solver, at the point before starting each timestep. The data from the most important features and the target properties were collected from a series of simulation cases and the DL model was trained with the Adam optimizer. After training and testing, the default initialization approach (i.e., solution at previous timestep) was replaced by the hybrid DL-based approach that provides an initial guess for cells with high saturation gradients. Saturation gradients at the previous timestep, location, and mobility ratio of both phases are selected as the input features. The results showed that applying the developed algorithm to numerical simulation problems reduced the run-time in the range of 15-35% in different cases, while the required processing time of the DL model was only around 1-3% of the whole simulation. The model performed acceptably when the effective parameters are like porosity, permeability and capillary pressure deviated from the range of the training data in order of 100%. The model performance declined when this deviation increased. This hybrid initialization approach showed the possibility of applying DL methodologies for the improvement of the numerical simulation processes.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"96 12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127991453","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Key Innovation Technologies and Practice Effect of Polymer Flooding Field Application","authors":"Youyi Zhu, Jian Fan","doi":"10.2118/209696-ms","DOIUrl":"https://doi.org/10.2118/209696-ms","url":null,"abstract":"\u0000 Chemical flooding technique is the dominating EOR technique in China. Polymer flooding has entered into industrialized applications and has been applied on a large scale in Daqing sandstone reservoir. Now polymer flooding is expanding to other reservoirs such as conglomerate reservoir, complex fault block reservoir and high temperature and high salinity reservoir. The good EOR effect achieved by polymer flooding is closely related to the key innovation technologies.\u0000 Recent progress of field tests and application of polymer flooding enhanced recovery (EOR) in China was summarized in this paper. Key technical innovations and field application effects was introduced. The challenges faced and the development direction of polymer flooding technology was discussed.\u0000 Polymer flooding has been applied in Daqing Oilfield from medium-high permeability reservoirs (type I reservoirs) to medium-low permeability reservoirs (type II reservoirs) with poor petrophysical properties. In addition, polymer flooding solution was prepared by dilution of produced water instead of fresh water. 13% incremental oil recovery in average has been obtained. Polymer flooding has expand apply to conglomerate reservoir in Xinjiang Oilfield, complex fault block reservoir in Dagang Oilfield and high temperature and high salinity reservoirs in Shengli Oilfield, the application results was also successful by solving bottleneck technical problems. A series of technologies have been developed for industrialization application of polymer flooding during tests and application. The key innovations are: polymer product evaluation and molecular weight optimization techniques; development of numerical simulation software and optimization of field test scheme; high efficient injection equipment and process; profile modification during polymer flooding; separated layer injection technique; separated molecular weight and pressure injection technology; anti-eccentric wear lifting technology; fracturing and injection technology; dynamic tracking and adjustment technology; produced liquid treatment technology. These innovative techniques ensure good results of polymer flooding in field applications. The key points and practical application of these technologies are illustrated with examples.\u0000 Polymer flooding is the leading EOR technology for medium and high permeability reservoirs. Polymer flooding has been applied on a large scale and is being extended to more complex reservoirs. Facing new technical challenges, it is necessary to continuously strengthen the research and development of new functional polymers, research of reservoir adaptability and continuously technological innovation of supporting technology for different types of reservoir application.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116331659","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Simulation Evaluation of CO2-ECBM Potential in Karaganda Coal Basin in Kazakhstan","authors":"Galymzhan Serikov, Lei Wang, M. Asif, R. Hazlett","doi":"10.2118/209698-ms","DOIUrl":"https://doi.org/10.2118/209698-ms","url":null,"abstract":"\u0000 Karaganda Coal Basin is the largest coal basin in Kazakhstan with around one trillion cubic meters of coalbed methane, which has not been tapped to date. Also, simulation research on the production of coalbed methane from the Karaganda Coal Basin has not been conducted. Seeing that primary production of coalbed methane (CBM) is generally slow and recovery is not high, we proposed to evaluate the potential of implementing CO2-ECBM processes in Karaganda Coal Basin in Kazakhstan. It is known that CO2 adsorption on coal is much higher than methane so it is important to study the displacement mechanisms by CO2 injection. Using the geological parameters collected for Karaganda Coal Basin, main factors affecting methane production including different rates of CO2 injection and different starting times of CO2 injection were simulated and compared. CO2 injection into CBM reservoir is predicted to be effective due to competitive adsorption of these gases. This study provides a workflow model for evaluating and predicting efficient CBM production from the Karaganda Coal Basin. Results from simulation studies showed that injection of 110,000 m3/day of CO2 is as practical as injection of 150,000 m3/day, with small difference in recovery factor. The methane production enhances from 68.32% to 73.67-74.62% at injection pressure 15,000 kPa. The CO2 injection after 30% of primary recovery is the most efficient option. Early injection results in early breakthrough and high CO2 content in the producer well, while late injection leads to relatively low incremental recovery factor.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122018004","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Limitations of Commercial Software in Estimating Trapped Gas Saturation and Hysteresis in Relative Permeability","authors":"S. Aghabozorgi, M. Sohrabi","doi":"10.2118/209642-ms","DOIUrl":"https://doi.org/10.2118/209642-ms","url":null,"abstract":"\u0000 Permanent storage of carbon dioxide requires accurate estimation of trapped gas saturation and reservoir storage capacity. Hydrogen and gas storage in subsurface reservoirs involves injection and withdrawal cycles, which necessitates the accurate estimation of hysteresis in relative permeability (kr) and capillary pressure (Pc) data. Cyclic injections in the form of Water Alternating Gas (WAG) injection is an effective Enhanced Oil Recovery (EOR) method for improving volumetric sweep efficiency in the reservoirs. When simulating all these processes, subsurface reservoir engineers rely on commercial software to estimate trapped gas saturation and cyclic hysteresis in kr and Pc data. However, few researchers have investigated the reliability of the available hysteresis models implemented in commercial software for this purpose.\u0000 To this aim, a thorough sensitivity analysis was performed to investigate the performance of three-phase hysteresis models available in the literature for simulating the measured data of cyclic experiments. The Water Alternating Gas (WAG) experiment used in this study was performed at near-miscible conditions on a mixed-wet sandstone sample, and the cyclic injection was started with drainage.\u0000 The results show that when simulating WAG experiments performed at low injection rates, using a hysteresis model developed by Aghabozorgi and Sohrabi (2019) provides the most accurate results for pressure drop, fluid saturations, and gradual oil production. However, the model developed by Larsen and Skauge (1998) can be only used for experiments reaching maximum gas saturation in their first three-phase imbibition cycle, mostly representing the limited grid blocks near the wellbore. Even in this scenario, the dependence of the model on Land’s initial-residual relationship and trapping coefficient is questionable.\u0000 This study highlights the possible pitfalls of using commercial software for estimating trapped saturation and hysteresis in relative permeability and capillary pressure. It also provides useful suggestions for improving the accuracy of performed simulations. The presented results are vital for the oil and gas experts as they can demand improvements in current approaches and promote constant growth and development of commercial software.","PeriodicalId":311361,"journal":{"name":"Day 3 Wed, June 08, 2022","volume":"314 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127720523","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}