Critical Gas Saturation Research Articles

Fast mass transfer processes of interfering trapped CO2-clusters at reservoir conditions: Experiment and theory

The gas-to-oil ratio (GOR) of a reservoir fluid plays a critical role in optimizing oil recovery and oil production strategies, improving oil recovery efficiency, and predicting reservoir behavior. Understanding the complicated kinetics of multicomponent mass transfer at the pore scale after gas injection into petroleum reservoirs is of great importance for estimating GOR and enhanced oil recovery (EOR). However, to date, there is a significant gap in the fundamental process understanding of the complex mass transfer process at reservoir conditions. Using micro-CT technology, we investigate the time dependence of CO2 mass transfer and cluster growth after high pressure CO2 injection into sedimented porous media (sintered 0.2 mm glass beads).Surprisingly, the CO2 partitioning equilibrium is already reached after 2 h. To the best of our knowledge, such a fast CO2 transport through water-saturated porous media, which cannot be explained by linear diffusion models (time scale 100 days for a diffusion length of 10 cm), has not been reported in the literature before. We proposed a conceptual model that assumes CO2 inflation of interfering gas clusters drives cascading CO2 transport. We verified this conceptual model through a time series of experiments at different initial gas saturation, analyzing in each case the spatial cluster distribution, cluster size distribution, and pore occupancy frequency.Whether CO2 inflation of the gas clusters occurs depends on the critical initial gas saturation, which is about 10%. Our main conclusion is that CO2 migration should be considered as gas phase diffusion cascading along a quasi-percolating cluster, since CO2 inflation leads to a high gas saturation of about 26%, which is close to the percolation threshold. Our experimental results support this physical hypothesis. We show for the first time that CO2 clusters can expand over large pore spaces and thus are close to the critical percolation threshold (mobility threshold). The cluster size distribution can be described by a power distribution with the critical exponent 2.19, i.e., it shows universal scaling.We model the interfering mass transfer processes of neighboring gas clusters with a multi-sphere model. Exploring different scenarios for the dissolution kinetics of an ensemble of interfering gas clusters allow a deeper understanding of the complicated mass transfer kinetics and agree well with experimental cluster analyses at specific times.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

An Analytical Method for Timely Predicting of Coal Seam Pressure during Gas Production for Undersaturated Coalbed Methane Reservoirs

Coal seam pressure is an important parameter for production performance evaluation and prediction of coalbed methane (CBM). CBM production from undersaturated CBM reservoirs can be divided into two stages according to critical desorption pressure. At present, few prediction models of coal seam pressure performance consider the comprehensive influence of critical desorption pressure, dissolved gas, matrix shrinkage, and stress sensitivity. For the purpose of accurately predicting coal seam pressure during gas production for an undersaturated coalbed methane reservoir, the material balance principle is used to establish the analytical method for predicting coal seam pressure, considering the comprehensive influence of the critical desorption pressure, dissolved gas, matrix shrinkage, and stress sensitivity. Then, the proposed method is verified against a numerical simulation case using a computer modelling group (CMG) and two actual coalbed methane wells. Finally, the sensitivities of influencing factors on the coal seam pressure are analyzed. The results show that good agreements were obtained between the calculated coal seam pressures using the proposed method and those from the CMG-GEM simulation case and actual CBM wells, with the relative errors all being less than 1%. When ignoring the influence of critical desorption pressure and mistaking pd for pi as well as ignoring Cs, the relative error can reach as high as 31.3%. The main factors affecting the coal seam pressure are the critical desorption pressure and free gas saturation. The proposed method is simple to use, and without shutting-in the well, it can provide an important basis for production performance evaluation and development strategies.

Monte Carlo simulation of the maximum migration distance of CO[formula omitted] in a sloping aquifer

Carbon capture and storage in saline aquifers is broadly considered a viable technology for reducing anthropogenic impact on the environment. However, a secure CO2 storage can be compromised by the depositional environments of target reservoirs, which can influence the CO2 migration in subsurface. The disposal of CO2 in a sloping aquifer can result in a substantial gas migration in the updip direction from the injection well until all gas becomes trapped. It thus can reach far more than desired regions from the well where the potential leakage paths to the surface can exist. This study aims at understanding the principal parameters that the maximum migration distance in the updip direction depends on, which can be important for estimating the risks of CO2 leakage through old abandoned wells in the regions of intensive subsurface exploration. Using the Monte Carlo method, an extended parametric study is performed by running 3-D reservoir simulations of CO2 storage in random aquifers characterized by various petrophysical and thermobaric parameters, saturation functions and brine salinity, and for the wells operated under different target rates. Herewith, the modeling accounts for such relevant physical phenomena as the phase transitions, the gravity and capillary forces, the hysteresis behavior of the relative permeability, etc. It is shown that the maximum migration distance at the post-injection stage is characterized by just two similarity criteria and the critical gas saturation for the drainage and imbibition processes. It is found that the CO2 plume shape at the moment of the well shut-in influences the subsequent gas transport. A new simple relation parameterizing the revealed dependence is proposed and validated against the sampled maximum migration distances. The relation is useful for an instant estimating the size of the contaminated zone around a projected CO2 well and for ranking the potential storage sites.

Understanding diffusion-controlled bubble growth in porous media using experiments and simulations.

Nucleation and subsequent expansion of gas bubbles in porous media is relevant to many applications, including oil recovery, carbon storage, and boiling. We have built an experimental setup using microfluidic chips to study the dynamics of bubble growth in porous media. Visualization experiments of the growth of carbon dioxide bubbles in a supersaturated dodecane solution were conducted. We show that bubbles grow as dissolved gas molecules inside the oversaturated liquid diffuse to the gas-liquid interface. Bubbles expanding inside a porous medium displace the liquid phase until the cluster of the gas-filled pores becomes connected to the outlet at the critical gas saturation, which is used as a measure for the total liquid displacement. Our experiments uniquely focus on the growth of a single bubble and show that larger pressure drops lead to faster bubble growth while resulting in lower critical gas saturations. A nonlinear pore-network model is implemented to simulate bubble growth. We compare model predictions for bubble growth dynamics to our experimental results and present the need for further theoretical development to capture deviations from invasion-percolation when a large pressure drop is applied.

Modeling evaluation of physiochemical processes controlling gas migration in shallow groundwater systems

Gases may be released into shallow groundwater systems during energy development and geological carbon storage (commonly referred to as gas migration, GM) and can result in greenhouse gas emissions, safety concerns, and the reduction of groundwater quality. The physiochemical processes occurring during GM, including gas release, movement, partitioning, and dissolved-phase transport in the saturated groundwater zone, are difficult to characterize and model; however, modeling is important to develop strategies for detecting and monitoring GM and formulate conceptual models to describe GM at impacted sites. In this study, a previously developed numerical model, which coupled macroscopic invasion percolation (macro-IP) and multicomponent mass transfer, was enhanced to simulate gas releases in the shallow subsurface. Evaluation of the effects of the coupled physiochemical processes was performed by comparing model simulations to previously conducted bench-scale gas injection experiments. Results show that gas flow is highly sensitive to the entry pressures assigned within the model domain and the critical gas saturation (Sg,crit) used to model gas-water flow based on macro-IP; however, mass transfer and the resulting domain-scale dissolved-gas transport were relatively insensitive to these parameters. Multicomponent mass transfer, considering not only the partitioning of the released gas, but also the dissolved background gases ubiquitous in shallow groundwater, was vitally important to simulate dissolution and the resulting free-phase gas distribution within the experimental systems. The use of the local equilibrium assumption for gas-water mass transfer could not consistently describe the experimental observations. Overall, the modeling evaluation performed in this study provides improved understanding of the key processes controlling GM in the shallow subsurface and will advance efforts including up-scaling and scenario testing to accurately quantify the environmental impacts of GM.

Impact of Gas Liberation Effects on the Performance of Low Permeability Reservoirs

Production from the North Sea reservoirs often results in a pressure decrease below the bubble point. The gas is liberated from oil, in the form of bubbles or as a continuous flowing phase. In such cases, the two phases, gas and oil, flow in the reservoir simultaneously, and the flow is governed by the values of relative permeabilities. Traditional core flooding in low permeability rocks is challenging, therefore we use a novel experimental approach to determine the oil relative permeabilities below the critical gas saturation. A mathematical model has been created to reconstruct both the gas and the oil relative permeabilities for the whole saturation range. Laboratory observations have shown that in low-permeable rocks the relative permeabilities may strongly decrease, even when the amount of the liberated gas is small. The goal of this work is to verify, on a specific example, whether the designed model for the relative permeabilities may explain the observed production behavior for a low-permeable chalk reservoir in the North Sea. We perform a sensitivity study using the parameters of relative permeabilities and analyze the corresponding differences in well productivities. A reasonably good match of <10% can be obtained to the historical well production data. A few cases where the match was not satisfactory (14% to 65%) are also analyzed, and the difference is attributed to the imprecise fluid model. The developed experimental and modeling methodology may be applied to other reservoirs developed by the solution gas drive mechanism.

Equilibrium modeling of water-gas systems in Jurassic–Cretaceous reservoirs of the Arctic petroleum province, northern West Siberia

To reveal the equilibrium state of oil and gas and water in a petroliferous basin with a high content of saline water, calculations of water-gas equilibrium were carried out, using a new simulation method, for the Arctic territories of the West Siberian oil and gas bearing province. The water-bearing layers in this area vary widely in gas saturation and have gas saturation coefficients (Cs) from 0.2 to 1.0. The gas saturation coefficient increases with depth and total gas saturation of the formation water. All the water layers with gas saturation bigger than 1.8 L/L have the critical gas saturation coefficient value of 1.0, which creates favorable conditions for the accumulation of hydrocarbons; and unsaturated formation water can dissolve gas in the existent pool. The gas saturation coefficient of formation water is related to the type of fluid in the reservoir. Condensate gas fields have gas saturation coefficients from 0.8 to 1.0, while oil reservoirs have lower gas saturation coefficient. Complex gas-water exchange patterns indicate that gas in the Jurassic–Cretaceous reservoirs of the study area is complex in origin.

Role of critical gas saturation in the interpretation of a field scale CO2 injection experiment

Residual trapping of CO2, typically quantified by residual gas saturation (Sgr), is one of the main trapping mechanisms in geological CO2 storage (GCS). An important additional characteristic parameter is critical gas saturation (Sgc). Sgc determines at what saturation the trapped gas remobilizes again if gas saturation increases due to exsolution from the aqueous phase, rather than from further gas injection. In the present study, a pilot-scale CO2 injection experiment carried out at Heletz, Israel, in 2017, is interpreted by taking critical saturation into account. With regards to this experiment, the delayed second arrival peak of the partitioning tracer could not be captured by means of physical models. In this work, the hysteretic relative permeability functions were modified to account for Sgc. The results showed that accounting for the effect of Sgc during the secondary drainage indeed captured the observed delayed peak. The difference between the values of Sgr and Sgc, influenced both the time and peak height of the tracer arrival. To our knowledge this is first time that critical gas saturation has been considered in field scale analyses related to GCS. Accounting for Sgc is relevant where gas saturation during secondary drainage increases due to gas phase expansion or exsolution from the aqueous phase. This will happen in situations where pressure depletion occurs, e.g. due to gas leakage from fracture zones or wells or possibly because of pressure management activities. The findings also have implications for other applications such as underground gas storage as well as for geothermal reservoir management.

Study of the Critical Pore Radius That Results in Critical Gas Saturation during Methane Hydrate Dissociation at the Single-Pore Scale: Analytical Solutions for Small Pores and Potential Implications to Methane Production from Geological Media

We examine the critical pore radius that results in critical gas saturation during pure methane hydrate dissociation within geologic porous media. Critical gas saturation is defined as the fraction of gas volume inside a pore system when the methane gas phase spans the system. Analytical solutions for the critical pore radii are obtained for two, simple pore systems consisting of either a single pore-body or a single pore-body connected with a number of pore-throats. Further, we obtain critical values for pore sizes above which the production of methane gas is possible. Results shown in the current study correspond to the case when the depression of the dissociation temperature (due to the presence of small-sized pores; namely, with a pore radius of less than 100 nm) is considered. The temperature shift due to confinement in porous media is estimated through the well-known Gibbs-Thompson equation. The particular results are of interest to geological media and particularly in the methane production from the dissociation of natural hydrate deposits within off-shore oceanic or on-shore permafrost locations. It is found that the contribution of the depression of the dissociation temperature on the calculated values of the critical pore sizes for gas production is limited to less than 10% when compared to our earlier study where the porous media effects have been ignored.

Experimental determination of relative permeabilities and critical gas saturations under solution-gas drive

Relative permeabilities are crucial to predict oil production from underground reservoirs. Multiple previous studies are limited to measuring/estimating relative permeabilities within the region where both phases are mobile. This study presents a novel experimental method to measure the oil relative permeability under presence of the trapped gas for gas-oil systems under depressurization. The experiments were carried out with the carbonaceous reservoir and outcrop samples. The results show a highly variable amount of immobile gas for North Sea chalk (from 8% up to 26% volume) and a significant reduction in oil relative permeability (up to 75%). The relative permeabilities were found to be power-law type functions. A comparison with the previously developed pore-network based model for gas-oil relative permeabilities is presented, allowing for reconstruction of both gas and oil relative permeability curves in the whole saturation range.

Capillarity and phase-mobility of a hydrocarbon gas–liquid system

When oil fields fall during their lifetime below the bubble point gas comes out of solution. The key questions are at which saturation the gas becomes mobile (“critical gas saturation”) and what the gas mobility is, because mobile gas reduces the production of oil significantly. The traditional view is that the gas phase becomes mobile once gas bubbles grow or expand to a size where they connect and form a percolating path. For typical 3D porous media the saturation corresponding to this percolation limit is on the order of 20%. However, significant literature report on gas mobility below lower limits of percolation thresholdsi.e.below 0.1%. A direct experimental insight for that is lacking because laboratory measurements are notoriously difficult since the formation of gas bubbles below the bubble point includes thermodynamic and kinetic aspects, and the pressure decline rates achievable in laboratory experiments are orders of magnitude higher than the decline rates in the field. Here we study the nucleation and transport of gas coming out of solutionin-situin 3D rock using X-ray computed micro tomography which allows direct visualization of the nucleation kinetics and connectivity of gas. We use either propane or a propane–decane mixture as model system and conduct pressure depletion in absence of flow finding that – consistent with the literature – observation of the bubble point in the porous medium is decreased and becomes pressure decline rate dependent because of the bubble nucleation kinetics. That occurs in single-component systems and in hydrocarbon mixtures. Pressure depletion in absence of flow results in critical gas saturations between 20 and 30% which is consistent with typical percolation thresholds in 3D porous structures. That does not explain experimentally observed critical gas saturations significantly below 20%. Also, the respective pore level fluid occupancy where pores are filled with either gas or liquid phase but not partially with both as in normal 2-phase immiscible systems rather diminishes connectivity of gas and liquid phases. This observation indicates that likely other mechanisms play a role in establishing gas mobility at saturations significantly below 20%. Experiments under flow conditions, where gas is injected near the bubble point suggest that diffusion may significantly contribute to the transport of gas and may even be the dominant transport mechanism at field relevant flow rates. The consequence of diffusive transport are compositional gradients where locally the composition is such gas nucleation may occur. That would lead to a disconnected but mobile gas distribution ahead of the convective front. Furthermore, diffusive exchange leads to ripening and anti-ripening effects which influences the distribution for which we see evidence in pressure depletion experiments but not so much at low rate gas injection. Respective relative permeability computed from the imaged fluid distributions using a lattice Boltzmann approach show distinctly different behavior between pressure depletion and flowing conditions. These findings suggest that capillarity in a gas–liquid hydrocarbon mixture is far more complex than in a 2-phase immiscible system. Capillarity is coupled to phase behavior thermodynamics and kinetics on a fast time scale and diffusion-dominated mechanisms such as ripening and anti-ripening effects at a slow time scale. While the consequences for the current experimental and field modelling approaches are not yet fully clear, this shows that more research is needed to fully understand these effects and their implications.

Gas‐Driven Tensile Fracturing in Shallow Marine Sediments

AbstractThe flow of gas through shallow marine sediments is an important component of the global carbon cycle and affects methane release to the ocean and atmosphere as well as submarine slope stability. Seafloor methane venting is often linked to dissociating hydrates or gas migration from a deep source, and subsurface evidence of gas‐driven tensile fracturing is abundant. However, the physical links among hydrate dissociation, gas flow, and fracturing have not been rigorously investigated. We used mercury intrusion data to model the capillary drainage curves of shallow marine muds as a function of clay content and porosity. We combined these with estimates of in situ tensile strength to determine the critical gas saturation at which the pressure of the gas phase would exceed the pressure required to generate tensile fractures. Our work showed that fracturing is favored in the shallowest 38 m of sediment when the clay‐sized fraction is 0.2, but fracturing may be possible to a depth of 132 m below seafloor (mbsf) with a clay‐sized fraction of 0.5 and to a depth of nearly 500 mbsf with a clay‐sized fraction of 0.7. Dissociating hydrate may supply sufficient quantities of gas to cause fracturing, but this is only likely near the updip limit of the hydrate stability zone. Gas‐driven tensile fracturing is probably a common occurrence in the upper 10–20 mbsf regardless of clay‐sized fraction, does not require much gas (far less than 10% gas saturation), and is not necessarily an indication of hydrate dissociation.

The Effect of Fracturing Fluid Saturation on Natural Gas Flow Behavior in Tight Reservoirs

Hydraulic fracturing becomes an essential method to develop tight gas. Under high injection pressure, fracturing fluid entering into the formation will reduce the flow channel. To investigate the influence of water saturation on gas flow behavior, this study conducted the gas relative permeability with water saturation and the flow rate with the pressure gradient at different water saturations. As the two dominant tight gas-bearing intervals, the Upper Paleozoic Taiyuan and Shihezi Formations deposited in Ordos Basin were selected because they are the target layers for holding vast tight gas. Median pore radius in the Taiyuan Formation is higher than the one in the Shihezi Formation, while the most probable seepage pore radius in the Taiyuan Formation is lower than the one in the Shihezi Formation. The average irreducible water saturation is 54.4% in the Taiyuan Formation and 61.6% in the Shihezi Formation, which indicates that the Taiyuan Formation has more movable water. The average critical gas saturation is 80.4% and 69.9% in these two formations, respectively, which indicates that the Shihezi Formation has more movable gas. Both critical gas saturation and irreducible water saturation have a negative relationship with porosity as well as permeability. At the same water saturation, the threshold gradient pressure of the Taiyuan Formation is higher than the one in the Shihezi Formation, which means that water saturation has a great influence on the Taiyuan Formation. Overall, compared with the Shihezi Formation, the Taiyuan Formation has a higher median pore size and movable water saturation, but water saturation has more influence on its gas flow capacity. Our research is conducive to understanding the effect of fracturing fluid filtration on the production of natural gas from tight reservoirs.

Study of the critical gas saturation during methane hydrate dissociation at the single-pore scale: Analytical solutions for large pores

Offshore/onshore deposits of methane hydrates could represent a large potential future source of energy, provided the difficulties associated with their safe, environmental-friendly and economically-viable production can be resolved adequately. Examining hydrate dissociation at different length scales (e.g., molecular, single pore, pore network, core and field) is part of the goal to initially identify, and subsequently address such difficulties. The current study introduces a mathematical-modeling approach and is focused on the evolution of methane gas that occurs within a single pore and is the result of the dissociation of methane hydrate that was originally deposited within the pore. We examine the critical gas saturation, which is defined as the fraction of gas volume inside a single pore when a spherical gas bubble reaches the pore walls for the first time. Further, we obtain critical values for pore sizes above which the production of methane gas is possible. The results shown here correspond to the case of large pores where the depression of the dissociation temperature (due to the presence of small-sized pores) is ignored.

Drawdown-Management and Fracture-Spacing Optimization in the Meramec Formation: Numerical- and Economics-Based Approach

Summary Optimal spacing between fracture clusters has eluded reservoir and completions engineers since the inception of multistage hydraulic fracturing. Very small fracture spacing could result in fracture to fracture (intrawell) interference and a higher completion cost, whereas very large fracture spacing could lead to inefficient hydrocarbon recovery, which is detrimental to the well economics. Meramec Formation has moved to full-field development, and multiple wells are put on production in a relatively short time. Depending on the desired economic metric, net present value (NPV), or rate of return (ROR), the magnitude of intrawell interference can be optimized by adjusting fracture spacing. For instance, if the objective is to maximize ROR, then tighter fracture spacing can be accepted. Furthermore, petroleum economics are often ignored in simulation studies, particularly the concepts of time value of money and oil-price sensitivity. This has led to a knowledge gap in identifying optimal drawdown procedure and fracture spacing from numerical models. This study proposes a framework that integrates petroleum economics with simulation results to optimize a horizontal well from the Meramec Formation. On the basis of this framework, we identified optimal drawdown procedure and fracture spacing. Then, oil-pricing sensitivity analysis was conducted to illustrate the effect of oil-price volatility on design parameters. Moreover, this study investigates the relative contribution of reservoir and completions characteristics with regard to short- and long-term well performance. These characteristics include drawdown management, fracture spacing, pressure-dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model that is used to history match a well from the Meramec Formation. The geologic model covers an area of 640 acres that encompasses a multistage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than 2 years of continuous production without being disturbed by offset operations. Findings suggest that the drawdown strategy (aggressive vs. conservative) has more effect on short-term oil productivity than fracture spacing. Drawdown strategy even has more of an effect on short-term oil recovery than does a 20% error in porosity, or water saturation. Furthermore, the profile of the producing-gas/oil ratio (GOR) depends on completions efficiency, and it has been interpreted using linear-flow theory.

Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

Thermal recovery processes for heavy oil exploitation involve three-phase flow at elevated temperatures. The mathematical modeling of such processes necessitates the account of changes in the rock–fluid system’s flow behavior as the temperature rises. To this end, numerous studies on effects of the temperature on relative permeabilities have been reported in the literature. Compared to studies on the temperature effects on oil/water-relative permeabilities, studies (and hence, data) on gas/oil-relative permeabilities are limited. However, the role of temperature on both gas/oil and oil/water-relative permeabilities has been a topic of much discussion, contradiction and debate. The jury is still out, without a consensus, with several contradictory hypotheses, even for the limited number of studies on gas/oil-relative permeabilities. This study presents a critical analysis of studies on gas/oil-relative permeabilities as reported in the literature, and puts forward an undeniable argument that the temperature does indeed impact gas/oil-relative permeabilities and the other fluid–fluid properties contributing to flow in the reservoir, particularly in a thermal recovery process. It further concludes that such thermal effects on relative permeabilities must be accounted for, properly and adequately, in reservoir simulation studies using numerical models. The paper presents a review of most cited studies since the 1940s and identifies the possible primary causes that contribute to contradictory results among them, such as differences in experimental methodologies, experimental difficulties in flow data acquisition, impact of flow instabilities during flooding, and the differences in the specific impact of temperature on different rock–fluid systems. We first examined the experimental techniques used in measurements of oil/gas-relative permeabilities and identified the challenges involved in obtaining reliable results. Then, the effect of temperature on other rock–fluid properties that may affect the relative permeability was examined. Finally, we assessed the effect of temperature on parameters that characterized the two-phase oil/gas-relative permeability data, including the irreducible water saturation, residual oil saturation and critical gas saturation. Through this critical review of the existing literature on the effect of temperature on gas/oil-relative permeabilities, we conclude that it is an important area that suffers profoundly from a lack of a comprehensive understanding of the degree and extent of how the temperature affects relative permeabilities in thermal recovery processes, and therefore, it is an area that needs further focused research to address various contradictory hypotheses and to describe the flow in the reservoir more reliably.

Modeling gas relative permeability in shales and tight porous rocks

Accurate modeling of gas relative permeability (krg) has practical applications in oil and gas exploration, production and recovery of unconventional reservoirs. In this study, we apply concepts from the effective-medium approximation (EMA) and universal power-law scaling from percolation theory. Although the EMA has been successfully used to estimate relative permeability in conventional porous media, to the best of our knowledge, its applications to unconventional reservoir rocks have not been addressed yet. The main objective of this study, therefore, is to evaluate the efficiency of EMA, in combination with universal power-law scaling from percolation theory, in estimating krg from pore size distribution and pore connectivity. We presume that gas flow is mainly controlled by two main mechanisms contributing in parallel: (1) hydraulic flow and (2) molecular flow. We then apply the EMA to determine effective conductances and, consequently, krg at higher gas saturations (Sg), and the universal scaling from percolation theory at lower Sg values. Comparisons with two pore-network simulations and six experimental measurements from the literature show that, in the absence of microfractures, the proposed model estimates krg reasonably well in shales and tight porous rocks. More specifically, we found that the crossover point – gas saturation (Sgx) at which transport crosses from percolation theory to the EMA – is non-universal. The value of Sgx is a function of pore space characteristics such as pore size distribution broadness and critical gas saturation. This means that one should expect Sgx to vary from one rock sample to another.

Determination of Critical Gas Saturation by Micro-CT

Determination of Critical Gas Saturation by Micro-CT

A compositional model for gas injection IOR/EOR in tight oil reservoirs under coupled nanopore confinement and geomechanics effects

The nanopore confinement and geomechanics are generally considered as non-negligible in tight oil reservoirs, but their coupled effects are still not well understood for gas injection which is becoming a favorable Improved/Enhanced Oil Recovery (IOR/EOR) technique for tight oil. We present a general compositional model to investigate the complex multiphase and multicomponent behaviors under coupled nanopore confinement and geomechanics in tight oil reservoirs. The in-house simulator developed is validated against a commercial simulator before being applied to simulate dry gas huff-n-puff in Eagle Ford. The simulation reveals that huff-n-puff would improve the recovery factor (RF) of each component versus the depletion. If the reservoir pressure is much higher than the bubble point, the nanopore confinement will have a minimal impact on RF for both the depletion and early cycles of huff-n-puff. Geomechanics is found to be an important factor for RF but not always detrimental, as enhanced compaction drive of matrix could offset the permeability reduction of fracture in certain scenarios. The heavy component would first have a higher RF than the light component in early huff-n-puff cycles, but its RF will be gradually outpaced by the light and finally surpassed after a crossover point which is controlled by the critical gas saturation of matrix. Considering the nanopore confinement in the simulation will delay this crossover and reduce the RF of the light component but increase the RF of the heavy component after huff-n-puff. This work can better assist engineers to understand the complex multiphase and multicomponent behaviors during gas injection in tight oil reservoirs.