Enhanced Gas Recovery Process Research Articles

Enhancing shale gas recovery: An interdisciplinary power-law model of hydro-mechanical-fracture dynamics

This study explores the efficiency of using carbon dioxide (CO2) to extract shale gas, highlighting its potential to enhance extraction while mitigating environmental CO2 pollution. Given the intricate microstructure of shale, CO2 injection inevitably induces deformation within the shale reservoir's internal microstructure, thereby impacting gas displacement efficiency. The organic matter (kerogen) network and fracture network in shale, serving as primary spaces for gas adsorption and migration, exhibit complex microstructural characteristics. Thus, we developed a dynamic coupled hydro-mechanics permeability model for binary gas displacement, and three novel, interdisciplinary fractal power-law parameters are proposed to represent the distribution of shale fractures, considering the adsorption–desorption strength of the kerogen network. Numerical simulations analyzed the changes in gas seepage, diffusion, shale stress, permeability, and factors influencing displacement efficiency during the CO2–EGR (enhanced gas recovery) projects. Key findings include (1) CO2 injection leads to a nonlinear increase in the number of shale fracture networks, thereby enhancing the CH4 output efficiency. (2) Compared to traditional fractal theory, the proposed power-law model is applicable to a wider range of reservoir fracture distributions and effectively characterizes the density (by α), size (by r), and complexity (by n) of the fracture network during the CO2–EGR process. (3) Changes in the proposed interdisciplinary power-law parameters significantly alter CO2 and CH4 adsorption capacities and, in turn, significantly affects displacement efficiency and shale deformation. According to calculations, these parameters have the greatest impact on the CO2–EGR process, ranging from 16.3% to 68.1%.

Investigating the flow behaviour of CO2 and N2 in porous medium using core flooding experiment

Several researchers employed N 2 to augment CH 4 recovery efficiency and CO 2 sequestration during the Enhanced Gas Recovery (EGR) process in consolidated rocks. To our knowledge, there has been limited data backing the reason why CO 2 experienced a more extended breakthrough during the EGR process in the presence of N 2 gas. This study investigated CO 2 and N 2 behaviour during the core flooding experiment by CO 2 injection in Bentheimer core plug. N 2 was used as the continuous phase during the core flooding process, while CO 2 was the dispersed phase. The experiment was designed with varying injection rates at 30 and 40 °C temperature points. The experimental findings showed that the dispersion and diffusion coefficient, CO 2 storage, concentration profile and breakthroughs were highly influenced by temperature change, especially at lower injection rates. However, at high injections, those properties are less sensitive to change in temperature, with most of the curves overlapping in the concentration profile. The highest and most negligible dispersion and diffusion coefficients were recorded at the highest and lowest injection rates respectively. These results agree with those reported by several researchers for sandstone rocks. Thus, higher temperatures have a more substantial effect on dispersion and diffusion coefficient, which eventually led to higher mixing between CO 2 and N 2 . The breakthrough time decreases with an increase in reservoir temperature, confirming the diffusion and dispersion coefficients are temperature dependent. The experiment at 30 °C recorded an extended breakthrough time over that at 40 °C. The maximum breakthrough time at 0.52 PV was recorded at 30 °C at the lowest injection rate. The concentration profile highlighted the trend between the displacing and displaced gas during the core flooding experiment. From the range of injections and temperatures tested, the CO 2 PV stored decreases as the rate of injection increases from 0.4 to 1.2 ml/min. However, the CO 2 stored was more promising at higher rates, corresponding with high differential pressure, due to flow resistance within the tortuous flow channels in the porous medium. • The maximum breakthrough of 0.52 PV was recorded at 30 °C at the lowest injection velocity. • The CO 2 stored was more promising at higher rates, corresponding with high differential pressure. • For 30 and 40 °C of temperature, α = 0.00222, and 0.002265 m. • Both N 2 and CO 2 experienced similar phase change behaviour at higher interstitial velocity.

Ab-Initio Molecular Dynamics investigation of gas adsorption on α-quartz (001) for CO2 enhanced natural gas recovery

In this work, the interaction of methane and carbon dioxide on α-quartz with surface 001, with a siloxane termination (dense) surface was investigated by means of Ab-Initio Molecular Dynamics. Different temperatures were addressed, ranging from 298 to 423 K. For completeness, pure and mixed compositions were considered, to replicate the conditions present during Enhanced Gas Recovery processes by CO 2 injection. When considering pure compositions, both gases stick to the surface, except for the highest temperature (423 K), where most of CH 4 tend to desorb. When mixed compositions are addressed, carbon dioxide generally hinders the interaction of methane, except for high temperature, where both gases are equally distributed both close and far from the surface. To the goal of improving EGR processes on sandstone reservoirs, this work shows that a temperature of 323 K offers the best efficiency by increasing the interaction of carbon dioxide and pushing methane out of the surface. At the same time, this study would not recommend the use of very high temperatures (T > 373 K) and excessive concentration of CO 2 , as the majority of this gas would desorb, without improving methane extraction in a meaningful way. • With pure compositions, CH 4 possesses high mobility on α-quartz compared to CO 2 , though both gases are characterized by the same interaction. • At room temperature and mixed composition, both gases interact strongly with the surface, so the extraction of methane is usually inefficient. • A temperature of 323 K offers the best EGR efficiency, improving carbon dioxide interaction with the surface and pushing methane out. • Very high temperatures and excessive concentration of CO 2 could reduce gas recovery and sequestration.

Computational analysis of feasibility of methane displacement by carbon dioxide during enhanced gas recovery from calcite-rich shale

Vast reserves of unharnessed shale gas, primarily CH4, present attractive and sustainable energy resources as an alternative to the current conventional petroleum-based energy resources. As in case of petroleum resources, an important question to address while harnessing these resources is the feasibility of their recovery in lean gas wells. Enhanced gas recovery techniques aim at the recovery of CH4 via its displacement by suitable gases. Mineral-gas interactions and the associated adsorption–desorption energetics have been conventionally used to predict the success of gas recovery operations. On the basis of adsorption–desorption energetics, CO2 has been proposed as one of the promising gases by several investigators. However, the mechanism of gas recovery involves the displacement of CH4 by CO2, which is an activated process, and the science behind the activated displacement needs to be explored. In this study, we have utilised van der Waals corrected density functional theory calculations to provide insights into shale-CH4 and shale-CO2 interaction energetics with calcite as the representative shale mineral. We have provided a detailed mechanism behind the displacement of CH4 by CO2 via a comparative sampling to its gas phase versus its displacement via surface diffusion. Our computational investigations conclusively prove the thermodynamic feasibility of the displacement of CH4 by CO2 with the adsorption of CO2 being one and a half times stronger than the adsorption of CH4 over a representative calcite surface. Further, our computational analyses also conclusively prove the kinetic feasibility of the displacement of CH4 by CO2 to its gas phase via crossing of an activation barrier of an acceptable magnitude. Finally, we have provided insights into the science behind the feasibility of successful CO2 sequestration during the enhanced gas recovery process.

The influence of CO2 and CH4 mixture on water wettability in organic rich shale nanopore

CO2 has been considered as an effective fluid to replace CH4 in shale rock. Wetting behavior of water in CO2/CH4 mixtures in organic nanopores is a key parameter influencing CO2 based enhanced gas recovery processes in shale. However, there is lack of fundamental understanding of water wetting in such systems. We perform Molecular Dynamics (MD) simulations of nanoscopic liquid water drops on a graphite substrate mimicking an organic-rich shale pore in the presence of CH4/CO2 mixtures at temperatures in the range 300 K–400 K. The equilibrium contact angle of the water droplets on graphite is a pronounced function of CH4 as well as CO2 pressure with the water droplet lifting-off, that is reaching a 180° contact angle, at a threshold pressure of 12 MPa for CO2 and 78 MPa for CH4. The contact angles recovered from simulations match well with experimental literature via the modified Young's equation. The line tension in our studied systems does not show a specific dependence on temperature. As compared to methane, CO2 exhibits a stronger interaction with organic-rich surfaces, which has strong impact on wettability. For CH4/CO2 mixtures, this translates in an approximately linear increase of the contact angle with the CO2 mole fraction.

Molecular dynamics computations of brine-CO2/CH4-shale contact angles: Implications for CO2 sequestration and enhanced gas recovery

The rock wettabilities and water contact angles describing interactions between CO2, CH4, brine and shale formations are of great significance to CO2 sequestration and enhanced gas recovery processes. However, water contact angles on the surfaces of shale organic matter in the atmospheres of CO2 and CH4 under reservoir conditions are not well-understood. In this study, we present an investigation of water/brine contact angles as functions of temperature, pressure, salinity, ion types, and gas contents by molecular dynamics simulations, and compare results with data from literature. It is found that temperature has profound effects on water contact angles below the critical temperature at an intermediate pressure. Meanwhile, water contact angles increase with pressure before reaching 180° at high pressure and the CO2-water-shale organic matter system turns from a neutrally-wet state to a CO2-wet state at the critical pressure of CO2. We also demonstrate that salinity and ion types have minor impacts on the brine contact angles in the CO2-brine-shale system. Only a slight increase in water contact angles is observed with increasing salinity, and an increase in brine contact angles caused by the divalent cations Mg2+ and Ca2+ is larger than that by the monovalent cations Na+ at the same salinity. Additionally, an increase in the CO2 fraction of gas mixtures can increase water contact angles at the same pressure and temperature. The surfaces of shale organic matter have a stronger affinity for CO2 than CH4, which contributes to a higher CO2 adsorption capacity and improves the displacement efficiency of CH4.

A theoretical study of gas adsorption on α-quartz (0 0 1) for CO2 enhanced natural gas recovery

The adsorption of gas molecules (CO2, CH4, H2O, H2S and N2) on the “dense” (0 0 1) surface of α-quartz has been investigated by means of Density Functional Theory (DFT) for the molecular characterization of Enhanced Gas Recovery (EGR) processes by CO2 injection. Several configurations have been studied for the different compounds. Overall, the five molecules are weakly physisorbed on the surface; no charge transfer takes place and no new bonds are formed. The potential surface is quite flat, with all the different values falling into a range of less than 0.15 eV. Consequently, all the molecules can easily move from a configuration to the other. As for the order of preference, hydrogen sulfide adsorbs the most with a maximum adsorption energy of −0.23 eV, followed by carbon dioxide with −0.21 eV. For the other three molecules (H2O, CH4 and N2), there is no net sequence but values lower than that of CO2 are inferred. Coverage analysis of CO2 and CH4 show that carbon dioxide can replace methane on the surface improving its extraction, but high CO2 concentration could weaken its adsorption, hindering the whole process. These results could prove to be useful in designing the EGR process based on CO2 injection.

Quantitative Tortuosity Measurements of Carbonate Rocks Using Pulsed Field Gradient NMR

Tortuosity is an important physical characteristic of porous materials; for example, it is a critical parameter determining the effective diffusion coefficient dictating mixing between miscible fluids in porous rock structures as is relevant to enhanced gas recovery processes. Accurate measurement of tortuosity remains challenging, resulting in various definitions dictated largely by the measurement protocol applied. Here, we focus primarily on ‘diffusive’ tortuosity (τd), which is defined as the ratio of the bulk fluid diffusion coefficient to the restricted diffusion coefficient applicable to the porous media under study. Specifically, we consider carbonate rock cores ranging in permeability from 2 to 5300 mD and adapt pulsed field gradient (PFG) NMR methodology such that accurate measurements of tortuosity are obtained over a sufficiently representative length scale of the porous media. To this end, we deploy supercritical methane as a probe molecule exploiting both its high mobility and proton density. Tortuosity measurements are shown to be independent of both pressure and diffusion observation time, conclusively proving that our measurements are in the asymptotic regime in which all of the pore space is adequately sampled by the diffusing methane molecules. The resultant ‘diffusive’ tortuosity measurements (which ranged from 3.1 to 5.6) are then compared against independent electrical conductivity measurements of tortuosity using a two-electrode impedance technique applied to the carbonate samples saturated with brine solution. Agreement between the ‘diffusive tortuosity,’ as measured by PFG NMR, and ‘electrical’ tortuosity was remarkably good (within 10%), given the very different measurements techniques used, for most of the carbonate rock samples considered.

CO2-EGR: Using CO2 to Enhance Gas or Condensate Recovery

A large number of gas fields in The Netherlands are in decline and within the next decade the production in many fields will cease. End-of-field-life techniques are currently being investigated. One of the options to extend economic field life is enhanced gas recovery (EGR). EGR is a technique to increase the ultimate recovery of natural gas and gas condensate through the injection of carbon dioxide (CO2), or another drive gas like nitrogen, in a gas field. The understanding of the field properties or EGR process parameters that determine the viability of EGR has been limited so far. The objective of this work is to find these success factors of EGR using CO2 as a drive gas and to investigate the potential for this type of utilization of CO2. A parameteric study was done on a realistic model of a gas field in the size range 1–5 bcm, varying a range of field properties (such as depth, GIIP, permeability) and EGR scenario parameters (such as injection rate, timing of the start of injection) to find the parameters that most affect additional recovery or the net present value of the EGR operation. This was done for both dry and wet (condensate) gas fields. For dry gas fields, the key parameters are field size (with larger fields presenting a better case for EGR), permeability (higher additional recovery is obtained in reservoirs of better quality). Typical additional recovery is in the range of 4–12% of the GIIP, depending on the concentration of CO2 that is allowed in the produced gas stream. EGR should not be started before the end of primary recovery; optimum injection rates are typically up to twice the production rate. A higher concentration results in more additional sales gas, at the cost of gas treatment to comply with sales gas specifications. In wet gas fields, best results are obtained when EGR starts as early as possible, to avoid condensate drop out in the reservoir. Although gas treatment requirements after CO2 breakthrough may cause loss of methane production, additional condensate recovery can be as large as 40%.

Investigating the effects of gas type and operation mode in enhanced gas recovery in unconventional reservoirs

A model that combines the Dusty-Gas approach and Darcy's Law is used to investigate the dynamics of production enhancement by gas injection in unconventional reservoirs. A comparison between CH4, N2 and CO2 injection in both Huff-n-Puff and Flooding operation modes is performed.The mechanism of production enhancement for each gas is different. CO2 can be injected to preferentially adsorb into the shale matrix, releasing hydrocarbons. In this case, the dominant mechanism is competitive adsorption. Due to stronger affinity with adsorption sites, CO2 injection would suggest high cumulative production. In spite of that, frontal displacement is very slow in this case, resulting in poorer short-term production when compared to N2 and CH4.N2 injection induces the release of hydrocarbons solely by partial pressure reduction. Frontal velocities are fast, resulting in high short-term production. Yet, since N2 is deemed inert, it does not replace components retained in the adsorbed phase.CH4 injection also prompts desorption of heavier hydrocarbons by partial pressure reduction. However, as heavier fractions are desorbed, CH4 molecules occupy the vacant sites. In this case, combined mechanisms of partial pressure reduction and uptake by the adsorption sites results in efficient release of heavier hydrocarbons.In this work, we demonstrate the impact of the presence of heavier hydrocarbon fractions in modeling gas transport during enhanced gas recovery processes. Multicomponent gas flow affects average reservoir pressure, produced gas composition and natural gas liquids (NGLs) yields, which is relevant for development of wet-gas and dry-gas unconventional reservoirs. Moreover, we demonstrate that injection gas composition significantly influences transport behavior of chemical species through the porous medium, and we highlight the relevant transport mechanisms during enhanced gas recovery in tight reservoirs.