Heterogeneous Gas Reservoirs Research Articles

Invasion Characteristics of Marginal Water under the Control of High-Permeability Zones and Its Influence on the Development of Vertical Heterogeneous Gas Reservoirs

In-depth understanding of the gas–water seepage law caused by different degrees of gas layer perforation and varying gas production rates is key to determining a reasonable development technology policy for vertical heterogeneous edge-water gas reservoirs. Based on core physical data from the entire section of the X2 well, a large-scale high-pressure positive-rhythm profile model that takes into account the influence of “discontinuous interlayer” was innovatively established. The water intrusion process of the gas layer profile under different gas production rates and degrees of gas layer perforation was simulated using an electrical resistivity scanning device. The experimental model has an area of 3000 cm2, with a maximum pressure of 70 MPa and a maximum temperature resistance of 150 °C. It includes 456 evenly distributed fluid saturation test points to accurately monitor the gas–water distribution, addressing the issues of small bearing pressure and insufficient saturation monitoring points found in other large-scale models. The experimental results show that, in heterogeneous reservoirs, the high-permeability zone controls the invasion path of edge water, which is the main reason for the uneven invasion of edge water. For the positive-rhythm profile of the F layer, a higher gas production rate (1000 mL/min) shortens the water-free gas recovery period of the gas well and reduces the recovery rate. Perforating the upper two-thirds of the layer can inhibit edge-water breakthrough, prolong the water-free gas recovery period of the gas well, enable the gas–water interface to advance more uniformly, and enhance the recovery degree. The results of this study greatly enhance our understanding of the water invasion characteristics of positive-rhythm reservoirs under the influence of different gas production rates and varying degrees of gas layer perforation.

Experimental Study on Edge Water Invasion of Strongly Heterogeneous Carbonate Gas Reservoirs Based on NMR Technology

Controlling the extent of water invasion in the reservoir and mitigating its detrimental effects on gas well production and natural gas recovery have long been a challenging task in the efficient development of strongly heterogeneous edge water gas reservoirs. To elucidate the edge water invasion mechanism of strongly heterogeneous carbonate gas reservoirs, this study investigates the pore throat characteristics and fluid mobility from both qualitative and quantitative aspects, leveraging natural core observations, cast thin sections, scanning electron microscopy (SEM), and nuclear magnetic resonance (NMR) tests with centrifuge experiments. A core-scale edge water invasion simulation experiment was conducted under online NMR monitoring to examine the dynamic gas production characteristics of the three types of reservoirs during the water invasion process and to elucidate the formation mechanism and distribution pattern of water-sealed gas. Research findings indicate that carbonate reservoirs typically exhibit a diverse range of pore types, including various types of fractures and cavities. Fractures significantly enhance reservoir connectivity, thereby increasing fluid mobility, but also lead to strong non-uniform water invasion. In contrast, cavities substantially improve the storage capacity of the reservoir and can retard the advancement of the water invasion front, thereby alleviating the adverse effects of water invasion. The ultimate recovery rates of fracture-type, cavity-type, and fracture-cavity cores in the water invasion simulation experiment were 29.81%, 64.87%, and 53.03%, respectively. Premature water breakthroughs in the reservoir can result in a large number of gases in matrix pores and even cavities being sealed by formation water, rendering them unrecoverable, which seriously impacts the gas recovery rate of the reservoir.

A pore-scale study on the dynamics of spontaneous imbibition for heterogeneous sandstone gas reservoirs

The underlying mechanism for spontaneous imbibition in a water–gas system plays a significant role in hydraulic fracturing in sandstone gas reservoirs. The objective of this study is to characterize the heterogeneity of low-permeability sandstones and investigate their effect on spontaneous imbibition from the perspective of the pore scale. We selected different cores with various pore structures and heterogeneity to evaluate their impact on the dynamics of spontaneous imbibition. The heterogeneities of the cores are contributed from the clay mineral distribution and are characterized through CT scans. The results show that clay minerals have higher CT numbers than the core matrix and that micropores are predominantly distributed in clay particles rather than in the core matrix. Additionally, the water imbibition rate of micropores is larger than that of the macropores, and when the porosities are similar, the water imbibition rate is increased with decreasing permeability. Moreover, the results of 1D frequency scans show that the distribution of water at different locations in the core is governed by the distribution of clay particles. These findings can help us further understand the distribution of fracturing fluids in the heterogeneous low-permeability sandstone reservoirs.

Study of the Seepage Mechanism in Thick Heterogeneous Gas Reservoirs

The seepage mechanism plays a crucial role in low-permeability gas reservoirs. Compared with conventional gas reservoirs, low-permeability sandstone gas reservoirs are characterized by low porosity, low permeability, strong heterogeneity, and high water saturation. Moreover, their percolation mechanisms are more complex. The present work describes a series of experiments conducted considering low-permeability sandstone cores under pressure-depletion conditions (from the Xihu Depression in the East China Sea Basin). It is shown that the threshold pressure gradient of a low-permeability gas reservoir in thick layers is positively correlated with water saturation and negatively correlated with permeability and porosity. The reservoir stress sensitivity is related to permeability and rock composition. Stress sensitivity is generally low when permeability is high or in the early stage of gas reservoir development. It is also shown that in sand conglomerates, especially the more sparsely filled parts, the interstitial materials among the conglomerates can be rapidly dislodged from the skeleton particles under stress. This material can therefore disperse, migrate, and block the pore throat producing serious, stress-sensitive damage.

Identification of formation plugging risk- A case study of gas reservoir in Deng4 member of Gaoshiti-Moxi block

Gaoshiti-moxi block of Anyue Gas field is a highly heterogeneous carbonate gas reservoir with low porosity and low permeability. According to the production dynamic data, deng4 gas reservoir in Gaoshiti-Moxi block is blocked to some extent. Combined with reservoir parameters, productivity parameters, gas well production curve, RTA analysis and other means, the cause of plugging in special single well was analyzed. Through various experiments, the composition of the plugging material is analyzed, and the formation mechanism of the plugging material is deduced, which provides a reference for the later gas field development and the research of plugging measures.

Analysis of development performance characteristics of strong heterogeneous carbonate gas reservoirs——the Deng 4 gas reservoir in the GM block

The Deng 4 gas reservoir in the GM block of Anyue gas field is an important area of natural gas production during the "13th Five-Year Plan" period. A correct understanding of its production dynamics is the key to scientific development of gas reservoirs and long-term stable production. Using gas reservoir engineering, production statistics, well test analysis, etc.，combined with gas reservoir geological characteristics, produced fluid properties, oil pressure production decline, gas well productivity, and single well controlled reserves, analyzed and summarized the Dengying Group gas in the block. The dynamic characteristics of production provide a reference for later efficient development.

Pressure transient analysis of a horizontal well intercepted by multiple hydraulic fractures in heterogeneous reservoir with multiple connected regions using boundary element method

The focus of this paper is to establish a new general model framework considering both hydraulic fractures with finite conductivity and heterogeneous characteristics of multiple connected regions by using boundary element method. With this framework, we can calculate the pressure performance of any heterogeneous reservoir. The innovation is that the complex fracture flow, boundary shape and heterogeneous characteristics can be flexibly considered in the model. Transient pressure of fractured horizontal wells in heterogeneous reservoir is obtained by using Stehfest numerical inversion method. Subsequently, this proposed regional heterogeneity model was validated by using numerical simulation methods. The results show that the proposed heterogeneous model can be divided into five flow segments, which are bilinear flow, linear flow, radial flow, first boundary dominated flow and second boundary dominated flow. However, the research results show that the presence or absence of some flow sections is closely related to the regional permeability ratio and the regional storage capacity ratio. As the two most important parameters of heterogeneous reservoir, the permeability ratio and regional storage capacity of heterogeneous reservoir will have a huge impact on the pressure response and pressure field. The sensitivity analysis shows that these two factors will lead to the deformation of the pressure field distribution and affect the flow characteristics, and cause some flow segments to fail to appear. The smaller the regional storage capacity ratio, the deeper the V-shape, and the more fluid supplied from the outer zone to the inner zone. This study also suggests that the fracture conductivity mainly affects the early flow characteristics, and the smaller the conductivity, the greater the pressure loss. In addition, irregular boundary will also cause important deformation of pressure field, and the area size will affect the late flow characteristics, and the smaller the area, the greater the pressure loss. The new semi-analytical solutions can form a series of typical curves and be applied to the well test analysis of multi-stage fracturing horizontal wells in heterogeneous and unconventional oil and gas reservoirs. The findings of this study can help for better understanding of the influence of reservoir heterogeneity on pressure response and find some applications in well testing for inverse problems in heterogeneous reservoirs.

A nonlinear model of multifractured horizontal wells in heterogeneous gas reservoirs considering the effect of stress sensitivity

Tight gas reservoirs are usually heterogeneous and associated with notable stress sensitivity during the production, directly influencing long-term development. This paper proposes a nonlinear model of multifractured horizontal wells in heterogeneous gas reservoirs considering stress-sensitive effects. Based on the linearization by stress-dependent pseudopressure and pseudotime functions, the boundary element method and Green's solution are applied to solve the model semianalytically. The effects of the stress sensitivity, production settings and subblock number are analyzed. The stress sensitivity is mainly reflected at the middle and later production stages, imposing a notable negative effect on bottomhole pressure, reducing the bottomhole pressure in a two-block reservoir by approximately 1%–28.2%. The recoveries in a two-block reservoir with different production settings under a terminal pressure vary from 16.3% to 42.49%, and thus a reasonable rate should be set to weaken the stress-sensitive effects on pressure loss to obtain a higher cumulative production within a given time. For a three-block reservoir, the proper increase of the fracture parameters in low permeability blocks can weaken the influences of heterogeneity and make the development more uniformly. This paper provides a theoretical basis for improving gas production performance forecasting for efficient development of natural gas.

Improving the Prediction of Production Loss in Heterogeneous Tight Gas Reservoirs Using Dynamic Threshold Pressure

Improving the Prediction of Production Loss in Heterogeneous Tight Gas Reservoirs Using Dynamic Threshold Pressure

Analysis of factors influencing recovery of low permeability and strong heterogeneous gas reservoirs and establishment of prediction model

Jialingjiang Formation is a typical low permeability carbonate reservoir in Sichuan Basin, which is characterized by strong heterogeneity, low matrix permeability and high-water saturation. Based on seven influencing factors, such as permeability, reservoir thickness and reservoir porosity, this paper evaluates and predicts the oil recovery of Jialingjiang Formation gas reservoir by using two neural network models of multilayer perceptor and radial basis function and nonlinear surface fitting method. The results show that: 1) In the neural network prediction model, the correlation coefficient between the prediction result curve of multilayer perceptron and the original recovery curve reaches 0.88, which is higher than the radial basis function (0.81), indicating that the use of multilayer perceptron can better predict the recovery of gas reservoirs. 2) In the nonlinear curved surface fitting prediction model, the two influencing factors with the greatest linear correlation with the recovery factor, reservoir thickness and gas recovery rate, are selected to fit the prediction model, and the prediction model is obtained. According to the prediction model, the recovery factor is positively correlated with the reservoir thickness and gas recovery rate on the whole. The model can be used to estimate gas recovery from two factors: reservoir thickness and gas recovery rate.

Production Behavior Evaluation on Inclined Well in Commingled Carbonate Gas Reservoir With Multiple Heterogeneous Layers Without Crossflow

Abstract To estimate production behaviors of inclined well in multilayer heterogeneous carbonate gas reservoir, two semi-analytical models for different formation distribution patterns are proposed, which are named as model I and model II. For model I, the inner region of each layer is fractured-vuggy porous medium, while the outer region only contains matrix. For model II, the inner and outer regions are consisted of matrix and fractured-vuggy porous mediums, respectively. To solve the model, Laplace transformation, Fourier transformation and inversion, Duhamel convolution, and Stehfest numerical inverse are applied. The validities of these models are verified through the comparisons with the published datum, which include well bottom-hole pressure (BHP) and gas production rate of individual layer for vertical and inclined wells in multilayer homogenous gas reservoir. Furthermore, by matching the well BHP data collected from a field case, the applicability of model is validated. The influences of prevailing factors, such as the radius ratio between inner and outer regions, horizontal–vertical permeability ratio, and inclination angle, on production behaviors are analyzed. The results show that influenced by the diverse formation distribution patterns, the variation of radius ratio between inner and outer regions has opposite effect on the well BHP for models I and II. Formation anisotropy and inclination angle have minimal effects on the well BHP of model I, but have significant impacts on model II. To keep the well BHP with a relatively high value, for model I and model II, the penetrate inclination angles should be greater than 50 deg and 55 deg, respectively.

Enhanced gas production of silty clay hydrate reservoirs using multilateral wells and reservoir reformation techniques: Numerical simulations

Multilateral wells and reservoir reformation techniques are widely employed to increase yield for spatially heterogeneous oil and gas reservoirs. However, the multilateral wells integrated with reservoir reformation have not been evaluated for low-permeability silty clay hydrate reservoirs before. Here, the multilateral well schemes without and with reservoir reformation technologies including burden sealing and hydraulic slotting were proposed, and their production behaviors under depressurization were evaluated and compared to that of a vertical well using available data in the South China Sea. The results show that the multilateral wells significantly enhance gas extraction because of a synergistic inter-borehole depressurization and an increase in production interval. Increasing branch hole number can further promote the synergistic effect and involved area, which enhances more hydrate dissociation, but this stimulation effect decreases with the extension of the production cycle in the silty clay reservoirs. The multilateral well with the hydraulic slotting is more suitable for short-term field trials and the burden sealing is better for long-term gas recovery. Combining hydraulic slotting or fracture and burden sealing technique at different production stages would be an extremely promising way for a multilateral well design to achieve long-term stable and high gas production in the low-permeability hydrate reservoirs.

A novel approach by integrating the core derived FZI and well logging data into artificial neural network model for improved permeability prediction in a heterogeneous gas reservoir

Predicting and extrapolating the permeability between wells to obtain the 3D distribution for the geological model, is a crucial and challenging task in reservoir simulation. Permeability is influenced by both digenetic characteristics and depositional factors like sorting and grain size. Hence, a reliable model should consider these characteristics for prediction of permeability. Grouping the rocks into different hydraulic flow units (HFU) or discrete rock types (DRT), improves the identity of the reservoir characteristics and provide a more accurate permeability prediction. Multi variable regression models and Artificial Neural Networks (ANN) were applied in this study to correlate core permeability and porosity with well logs to predict permeability logs. It was observed that the accuracy of the models diminished in heterogeneous reservoirs, where there is a wide permeability distribution.In this study, we are presenting a novel approach to predict permeability in heterogeneous oil and gas reservoirs. In this method the core permeability and porosity data are categorized using the concept of DRT and the probability density functions are used to investigate the relationships between the logs and DRT groups. The ANN model is applied to correlate the core derived flow zone indicator (FZI) with wire-line logging data with a single key well to predict K-logs. In this approach one single well, which contains all DRT groups is considered as a key well to develop and train the ANN model. It was observed that ANN model exhibits better prediction performance in heterogeneous reservoirs when it is developed and trained on single well data containing all DRT groups. This approach can capture heterogeneity in the reservoirs where it has been applied successfully to predict permeability in an actual heterogeneous carbonate gas reservoir.

Features of fluid dynamics in long-term heterogeneous gas reservoirs

Geological features are characterized by macro- and micro-heterogeneity, manifested by the spatial variability of material composition and lithophysical properties of rocks. This, in turn, determines the spatial and temporal variability of hydrocarbon (HC) fluid dynamics both during the reservoir formation and during its development and, subsequent operation as an underground gas storage facility (UGSF). The long-term operation of underground gas reservoirs at the Galmas and Garadagh areas in the South Caspian Basin (SCB), serving as a reservoir of commercial gas accumulations, and subsequent underground gas storage (UGSF) is characterized by significant peculiarities. Analysis of monitoring data on volumes of gas injection and extraction at the Galmas/Garadagh UGSF in the period of 2020–2021 showed their spatial variability, as well as the variability of wells deliverability during the gas reservoir development. This suggests the inherited nature of UGSF operation mode in relation to the gas reservoir development mode. The heterogeneous nature of spatial variability of these parameters is determined by the reservoir rock poroperm properties. A formation pressure drop during reservoir development is accompanied by decreasing rock permeability. When operating UGSF, the lithofacial properties of rocks determine the ratio of volumes of injected and extracted gas. In this regard, a necessary condition for selecting the optimal system of UGSF operation is to take into account the spatial heterogeneity of the underground reservoir. The irregular nature of variation of rock poroperm properties, the origination of isolated zones in the reservoir with considerable residual gas volumes, as well as unpredictable directions of fluid movement are the main reasons for decreased efficiency of field development and underground gas storage facility operation. In order to determine the optimal system of operation of UGSF in depleted underground oil and gas reservoirs, the features of the spacial variations resulting from the rocks poroperm properties need to be taken into account.

Fast modelling of gas reservoir performance with proper orthogonal decomposition based autoencoder and radial basis function non-intrusive reduced order models

Two new, non-intrusive reduced order frameworks for the faster modelling of gas reservoirs with time-varying production are presented and compared. The first method is an extension of a method using proper orthogonal decomposition (POD) in conjunction with radial basis functions (RBFs) that has previously been applied to predicting the performance of oil reservoirs undergoing a constant rate waterflood. The second method uses an autoencoder rather than RBFs to estimate the flow dynamics (pressure distributions) in hyperspace for unseen cases. Both frameworks are ‘trained’ using sample outputs from off-line, commercial reservoir simulations of a realistic heterogeneous gas reservoir with time-varying production controls typical of gas field operation. These controls include time-varying rate and switching between bottom hole pressure and rate control as well as cases where wells get shut-in. Both POD-based models produce reasonable forecasts of the reservoir performance for new unseen/prediction cases and are between 0.22 and 300 times faster than conventional simulation, including the time spent performing training simulations with conventional simulation solutions. The POD-RBF models are more accurate and consistent with reference commercial simulation outputs than the POD-AE models. In addition, the POD-AE models required more trial and error to set up as the number of hidden layers needed, depends on the particular scenario being modelled. There is no ab initio way of predicting the best number of layers for a given type of scenario. This makes them less suitable for practical application by reservoir engineers. Overall the POD-RBF framework is the most robust and accurate of the two methods. • Non Intrusive Reduced Order Modelling of real gas field from commercial simulator solutions. • Evaluation of machine learning and numerical techniques. • Modelling time-varying production scenarios with mixed boundary conditions and shut-in wells. • Estimation of spatial distribution of pressure in gas field.

An analysis method of injection and production dynamic transient flow in a gas field storage facility

A dynamic transient flow analysis method considering complex factors such as the cyclic injection and production history in a gas field storage facility was established in view of the limitations of the existing methods for transient flow analysis and the characteristics of the injection-production operation of strongly heterogeneous gas reservoirs, and the corresponding theoretical charts were drawn. In addition, an injection-production dynamic transient flow analysis model named “three points and two stages” suitable for an underground gas storage (UGS) well with alternate working conditions was proposed. The “three points” refer to three time points during cyclic injection and production, namely, the starting point of gas injection for UGS construction, the beginning and ending points of the injection-production analysis stage; and the “two stages” refer to historical flow stage and injection-production analysis stage. The study shows that the dimensionless pseudo-pressure and dimensionless pseudo-pressure integral curves of UGS well flex downward in the early stage of the injection and production process, and the dimensionless pseudo-pressure integral derivative curve is convex during the gas production period and concave during the gas injection period, and the curves under different flow histories have atypical features. The new method present in this paper can analyze transient flow of UGS accurately. The application of this method to typical wells in Hutubi gas storage shows that the new method can fit the pressure history accurately, and obtain reliable parameters and results.

The Fourier transform infrared spectroscopy (FTIR) analysis for the clay mineralogy studies in a clastic reservoir

The complete characteristics knowledge of clay minerals is necessary in the evaluation studies of hydrocarbon reservoirs. Ten samples taken from two wells in a heterogeneous clastic gas reservoir formation in NE Iran were selected to conduct the transmission Fourier transform infrared spectroscopy (FTIR) tests for the clay mineralogy studies. The FTIR analysis showed that there were clear signs of clay minerals in all samples. The wavenumber region of the clay minerals in FTIR tests was detected to be 3621, 3432, 1034, and 515 cm−1 for illite, 3567, 3432, 1613, 1088, 990, 687, 651, and 515 cm−1 for magnesium-rich chlorite, 3700, 3621, 3432, 1034, 687, and 463 cm−1 for kaolinite, and 3567, 1088, 990, and 463 cm−1 for glauconite. After screening of samples by the FTIR method, the samples were then analyzed by powder X-ray diffraction (PXRD), wavelength dispersive X-ray fluorescence (WDXRF), and scanning electron microscopy (SEM). The PXRD and SEM result showed illite was by far the most common clay present. Kaolinite, magnesium-rich chlorite, and traces of smectite and the mixed-layer clays of both the illite–smectite and chlorite-smectite types were also recognized. The combination of PXRD and WDXRF results could quantify the clay abundances in the each well too. It was concluded that the FTIR analysis successfully could show the absorption bonds of all constituent clays. However, the infrared absorption spectra of mixed-layer clays overlapped those of the respective constituents of each mixed-layer minerals. This can be considered as the evidence of the usefulness of FTIR technique in the screening of the samples for the clay mineralogy studies.

Semi-analytical modeling for multi-wing fractured vertical wells in a bilaterally heterogeneous gas reservoir

Many prolific hydrocarbon reservoirs show the lateral heterogeneity of rock properties, where the formation is composed of several regions with different rock properties separated by linear interfaces. Although there have been many studies on laterally heterogeneous reservoirs by linear composite models, most of them focus on vertical well without hydraulic fracturing. The modeling for fractured vertical wells in laterally heterogeneous reservoirs remains limited. The goal of this study is to develop a semi-analytical three-region linear composite model for multi-wing fractured vertical (MWFV) wells in a bilaterally heterogeneous gas reservoir. This model can take into account the common situation in practice, where the heterogeneity occurs on both sides of the reservoir region with the MWFV well. Based on the point-source function method, a semi-analytical modeling for an MWFV well in a bilaterally heterogeneous gas reservoir is developed by using pressure drop superposition, fracture wing discretization, and Stehfest algorithm. Compared with the simplified semi-analytical and numerical models, the correctness of the present model is verified. Log-log type curves for MWFV wells in a bilaterally heterogeneous gas reservoir are drawn. The flow regimes of the MWFV well in a bilaterally heterogeneous gas reservoir are identified. The influences of some well and reservoir parameters on the pressure response and rate decline of MWFV wells are investigated thoroughly. It is found that the pressure response and rate decline of MWFV wells are significantly affected by the well location, fracture wing properties, and reservoir heterogeneity.

Effect of Geological Heterogeneity on the Production Performance of a Multifractured Horizontal Well in Tight Gas Reservoirs

AbstractMultifractured horizontal wells are widely used in the development of tight gas reservoirs to improve the gas production and the ultimate reservoir recovery. Based on the heterogeneity characteristics of the tight gas reservoir, the homogeneous scheme and four typical heterogeneous schemes were established to simulate the production of a multifractured horizontal well. The seepage characteristics and production performance of different schemes were compared and analyzed in detail by the analysis of streamline distribution, pressure distribution, and production data. In addition, the effects of reservoir permeability level, length of horizontal well, and fracture half-length on the gas reservoir recovery were discussed. Results show that the reservoir permeability of the unfractured areas, which are located at both ends of the multifractured horizontal well, determines the seepage ability of the reservoir matrix, showing a significant impact on the long-term gas production. High reservoir permeability level, long horizontal well length, and long fracture half-length can mitigate the negative influence of heterogeneity on the gas production. Our research can provide some guidance for the layout of multifractured horizontal wells and fracturing design in heterogeneous tight gas reservoirs.

Simulation on Effects of Injection Parameters on CO2 Enhanced Gas Recovery in a Heterogeneous Natural Gas Reservoir

AbstractCO2 enhanced gas recovery (CO2‐EGR) is a promising technology to extract additional natural gas from depleted reservoirs with storing CO2 into underground formations. This work conducted CO2‐EGR simulations in a heterogeneous gas reservoir by using isothermal and non‐isothermal models and systematically analyzed the effects of various CO2 injection parameters on natural gas recovery, CO2 storage, and their comprehensive benefits. The results indicate that the CO2 injection well should be perforated in the lower position, whose overlaid layers with low permeability hinder the upward migration of CO2, and the larger natural gas recovery and CO2 storage can be achieved simultaneously for better comprehensive benefits. The optimal injection rate is 137.29 m3·d−1 to achieve the highest recovery factor of 64.87%. The decrease in injection temperature and the increase in injection pressure are averse to the enhancement of recovery but beneficial to larger CO2 storage. The comprehensive benefits of natural gas recovery and CO2 storage are insensitive to the change of injection pressure and temperature, despite that every single one of them is more subjective to injection pressure than temperature. It's hoped that the findings of this work provide some theoretical guidance for the application of CO2‐EGR.