Permeability Of Reservoir Rocks Research Articles

Experimental investigation of effect of asphaltene deposition on oil relative permeability, rock wettability alteration, and recovery in WAG process

Asphaltene deposition is considered to be one of the most problems during oil productions. This work describes the effect of asphaltene precipitation and deposition on relative permeability of reservoir rock during water alternating gas (WAG) injection process. The main objective of this work is experimental investigating of relative permeability change of reservoir fluid due to asphaltene deposition on application of WAG process by use of core flood setup. Result of this paper investigate the relative permeability change during WAG process with different asphaltene content that help to make better development decisions for a reservoir with fluid with specific asphaltene content.

The effect of alkaline\u2013surfactant on the wettability, relative permeability and oil recovery of carbonate reservoir rock: experimental investigation

Due to the increasing demand and the price of hydrocarbon fuels, today, cost-effective enhanced recovery of oil and gas reservoirs has become one of the most interesting research topics. Since the Iranian reservoirs have a considerable potential to apply the chemical EOR processes, it seems that extensive research in this field is inevitable. One of the most important enhanced oil recovery techniques is injecting alkaline–surfactant into the reservoir. Although injecting alkaline–surfactant has been investigated in many researches, few studies reported on the effect of this process on the oil/water relative permeabilities which control the recovery performance. Today, the need for EOR processes is critical. One of the newest ideas for this respect is the concept of altering the rock wettability to more water wet. This phenomenon leads to making a path for oil in the larger routes, therefore increasing the recovery. In most cases, waterflooding has a low effect and by increasing the water production, the oil recovery becomes non-economical. In most studies, the effect of solution injection has been considered. In this study, we have investigated the effect of chemicals on interfacial tension and the wettability alteration based on relative permeability curves. In this work, using three surfactants, anionic (SDS), cationic (CTAB) and nonionic (Triton X-100), with sodium carbonate alkaline, relative permeabilities, wettability, IFT and the recovery efficiency in the porous media in the core scale have been investigated. The results show that cationic surfactant has the most effect on reduction in IFT and changing the wettability to water wetness, which has 70% recovery factor. Anionic surfactant has a greater effect on the reduction in interfacial tension in comparison with nonionic surfactant. Furthermore, nonionic surfactant has the most effect on changing the wettability to water wetness in comparison with anionic surfactant. Moreover, the recovery enhancement in the case of injection of alkaline–nonionic surfactant (67%) is more considerable than alkaline–anionic (65%).

FT-ICR MS determination of the role of naphthenic acids on the stabilization of alkali/surfactant/polymer emulsified effluents: A field study

Numerous Alkali/Surfactant/Polymer flooding (ASP) projects have been developed worldwide. Nevertheless, some disadvantages have limited the success of ASP during the execution in field, such as injection lines scaling and strong emulsification of the produced fluids. Commonly, appropriate formulations for particular reservoir conditions are selected after a series of evaluation steps. These includes tests of surfactants, polymers and commercially available alkali, based on the reservoir temperature, reservoir salinity, reservoir water pH, rock permeability, formation type and adsorption of the surfactant on the matrix rock, to obtain the highest oil recovery at the lowest cost. As part of the different strategies adopted for increasing the oil recovery factor, San Francisco oil field, Huila Colombia, was selected in 2012 for ASP flooding application at pilot scale. After two years of injection, ASP effluents affected considerably the quality of water and its treatment for reinjection. The present work focuses on the compositional study of the production effluents obtained after ASP flooding. A detailed analysis using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) allowed disclosing the role of natural organic acids on reducing the interfacial tension which in turn entailed highly stable microemulsions. Together with the added surfactant, naphthenic acids (because of the alkaline pH) prompts the formation of these thermodynamically stable oil in water systems. A test using an acid free oil proved that the formation of microemulsions strongly depends on naphthenic acids presence. Additional tests using oils with different acidity showed the dependence on the naphthenics acids structure over the emulsion stability. The results obtained in this study stands out FT-ICR MS as a prominent tool on understanding breaking and/or clarifying treatment processes from a molecular level point of view and thus, could help on proposing a correct and cost effective water treatment.

A Method of Differentiating the Early-Time and Late-Time Behavior in Pressure-Pulse Decay Permeametry

The pressure-pulse decay is a preferred technique for determining permeability of unconventional gas reservoir rocks. The pressure-pulse decay often shows quite different characteristics during the early time and the later time. Most approaches for estimating the permeability proposed in the literature are required to use the later-time pressure-pulse decay measurements. However, the later-time data are often selected subjectively, lacking a universal criterion. In this paper, a method of differentiating the early-time and late-time behavior for pressure-pulse decay test is proposed. The analytical results show that the critical time (dimensionless time) of early-/late-time decay characteristics mainly depends on the volume ratios, and it increases first and then decreases with the volume ratios. The critical time for cases with same chamber sizes is much less than that for cases with unequal chamber sizes. Applicability of the proposed methods is examined using a numerical simulator, TOUGH+REALGASBRINE. The numerical results show that the pressure gradient along the sample varies nonlinearly at the early time and becomes a constant at the late time. Then, the proposed method is applied to real data for permeability estimation. It is found that the early-time behavior is negligible as the volume ratio takes on small values. As the volume ratios increase, the deviation becomes significant and considerable permeability errors will be produced if these early-time data are used.

Reservoir rock permeability prediction using SVR based on radial basis function kernel

Permeability is one of the most important parameters of the rock reservoir. This parameter represents the ability of fluid pass through the porous medium without changing the structure of the rock which plays a main role in the production rate of a hydrocarbon reservoir. Permeability could be obtained through laboratory using core plugs, although the measurements is highly accurate, but these analyses are costly, time-consuming, and also the core data are not available for all wells. Therefore, permeability is usually predicted using well logs by regression techniques. In this study, support vector regression (SVR) based on radial basis function is developed to estimate permeability in South Pars gas field of Iran. For this purpose, first four electrofacies were identified using a method called multi-resolution graph-based clustering (MRGC), and thereafter the method applied for each facies. To evaluate the prediction model, the correlation coefficient between the real permeability (determined from core plugs) and the estimated was calculated for each electrofacies. The values for the four electrofacies designated obtained 88.2, 78.51, 84.73, and 77.54 percent, respectively. The high amount of obtained correlations for each electrofacies demonstrates the power of the regression model for a reliable permeability prediction of the reservoir.

An experimental investigation into the characteristics of hydraulic fracturing and fracture permeability after hydraulic fracturing in granite

Geothermal energy, as a renewable energy source, can meet the growing need for energy associated with low atmospheric emissions. Hydraulic fracturing is a promising simulation technique used in enhanced geothermal systems to increase heat production from a geothermal reservoir by enhancing reservoir rock permeability. This paper presents an experimental study on hydraulic fracturing of granite which is the most suitable hot dry rock type focusing on the effects of confining stress, water injection flowrate, and temperature on breakdown pressure and fracture permeability. Results indicate that the rock temperature is one of the more important factors affecting hydraulic breakdown pressure. The breakdown pressure increases with the increase of confining pressure. Additionally, as the injection flow rate increases, the breakdown pressure increases. In addition, the fracture permeability after hydraulic fracturing is calculated on the basic of pressure data recorded during hydraulic fracturing. The results can provide some guidance to those seeking to implement economical and reasonable hydraulic fracturing simulations and improve heat production capacity in EGS.

On producing CO2 from subsurface reservoirs: simulations of liquid‐gas phase change caused by decompression

AbstractCarbon dioxide (CO2) extraction from deep reservoirs is currently important in CO2 enhanced oil recovery (EOR) and may become more important in the future if interim CO2 storage becomes common. In late 2014, we were involved in a production test of liquid CO2 from the Middle Duperow dolostone at Kevin Dome, Montana. The test resulted in lowering the temperature at the well bottom to ∼2 °C, and showed that the well and reservoir had very low CO2 productivity. We have used the CO2 modeling capabilities of the TOUGH codes to simulate the test and to show that liquid CO2 in the reservoir changes to gas phase as the pressure is lowered in the well during production testing. The associated phase change and decompression combine to drastically lower the bottom‐hole temperature, creating the potential for water ice or CO2 hydrate to form. By hypothesizing a relatively high‐permeability damage zone near the well surrounded by lower permeability reservoir rock, we can match the observed pressure, temperature, and production rate. Moving from the Kevin Dome test to the question of CO2 extraction from deep reservoirs in general, we carried out a parametric study to investigate the effects of reservoir depth and transmissivity on CO2 production rate for a prototypical reservoir. Simulations show that depth and high transmissivity favor productivity. Complex phase changes within the ranges of P‐T encountered in typical CO2 production wells affect production rates. The results of our parametric study may be useful for the preliminary feasibility assessment of CO2 extraction from deep reservoirs. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Produced Water Re-Injection and Disposal in Low Permeable Reservoirs

Produced water re-injection (PWRI) is an important economic and environmental-friendly option to convert waste to value with waterflooding operations. However, it often causes rapid injectivity decline. In the present study, a coreflood test on a low permeable core sample is carried out to investigate the injectivity decline behavior. An analytical model for well impedance (normalized reciprocal of injectivity) growth, along with probabilistic histograms of injectivity damage parameters, is applied to well injectivity decline prediction during produced water disposal in a thick low permeable formation (Völkersen field). An impedance curve with an unusual convex form is observed in both coreflood test and well behavior modeling; the impedance growth rate is lower during external filter cake build-up if compared with the deep bed filtration stage. Low reservoir rock permeability and, consequently, high values of filtration and formation damage coefficients lead to fast impedance growth during deep bed filtration; while external filter cake formation results in relatively slow impedance growth. A risk analysis employing probabilistic histograms of injectivity damage parameters is used to well behavior prediction under high uncertainty conditions.

Analysis of filtration and electrical properties anisotropy of terrigenous reservoir rocks (for DDB axial zone reservoirs)

The paper focuses on the filtration and electrical anisotropy coefficients and relationship between vertical and horizontal permeability in sandstone reservoir rocks. Field case study of DDB reservoir rocks. Petrophysical properties and parameters are estimated from core and log data from a Moscovian and Serpukhovian stages of Dnipro-Donetsk Basin (West-Shebelynka area well 701-Bis and South-Kolomak area well 31). Routine core analysis included estimation of absolute permeability, open porosity, irreducible water saturation and electrical resistivity (on dry and saturated by mineralized solution) of 40 core samples along two orthogonal directions. Shale fraction is estimated using well logging data in wells which are analyzed. The authors report that reservoir rocks are represented by compacted poor-porous (φ <10 %), low permeable (k<1mD) laminated sandstone with different ratios of clay minerals (Vsh from 0,03 to 0,7) and high volume of micaceous minerals (in some cases 20-30 %). Research theory. One of the main objectives of the work is to develop empirical correlation between vertical permeability and other capacitive and filtration properties for compacted sandstone reservoirs. A modified Kozeny-Carman equation and the concept of hydraulic average radius form the basis for the technique. Results. Coefficients of the anisotropy of gas permeability (IA) and electrical resistivity (λ) are defined based on the results of petrophysical studies. The experiments proved that IA lies in a range from 0,49 to 5 and λ from 0,77 to 1,06. Permeability and electrical resistivity anisotropy in most cases have horizontal distribution. It has been shown that in West-Shebelynka area sample №1 (depth 4933 m) there is probably no fluids flow in vertical direction and in samples №№3 and 15 fractures have the vertical orientation. We have also found that the values of electrical and filtration anisotropy for all samples of South-Kolomak area are similar, this characterized the unidirectionality in their filtration properties, as well as the fact that the motion of the fluid flow mainly in the horizontal direction. In the studied rocks the degree of anisotropy has been concluded to depend on the volume of clay and micaceous minerals, their stratification, fractures, density, and their orientation. New correlation between vertical permeability, horizontal permeability and effective porosity are developed for Late Carboniferous DDB intervals that are analyzed.

Prediction of oil-water relative permeability in sandstone and carbonate reservoir rocks using the CSA-LSSVM algorithm

Relative permeability of multiphase flow through porous media plays a vital role in the petroleum industry, especially in enhanced oil recovery (EOR) processes. In this study, models were developed based on a combination of Least-Square Support Vector Machine and Couple Simulated Annealing (CSA-LSSVM) algorithm to predict oil-water relative permeability in sandstone and carbonate porous media. Comparing the model to thousands of experimental data resulted in overall squared correlation coefficients (R2) of 0.9866 and 0.9965, and minimum squared errors (MSEs) of 0.0014 and 0.000143 for Kro and Krw, respectively. In addition, Model predictions were found to agree excellently with experimental data. The results of CSA-LSSVM model were compared with some of the well-known mathematical equations including the Purcell, Burdine, Brooks and Corey, Corey, and some empirical correlations for predicting the oil-water relative permeability in a heterogeneous carbonate core sample. The models developed in this study outperform the mathematical equations and empirical correlations yielding an overall squared correlation coefficients of 0.9987 and 0.9994, and minimum squared errors of 0.0003 and 0.0049 for Kro and Krw, respectively. Finally, leverage value was introduced to analyze the whole dataset from which 19 points were diagnosed as possible outlier experimental data.

Characterizing the pore structure of low permeability Eocene Liushagang Formation reservoir rocks from Beibuwan Basin in northern South China Sea

The hydrocarbon exploration from low permeability (<50mD) reservoirs in Beibuwan Basin has been on the agenda because of the production decline of old wells and the growing demand of fossil fuel with the rapid economic development of China. However, these low permeability reservoir rocks usually exhibit strong heterogeneity and the complicated pore structure of these rocks, which significantly affects the reservoir quality, is still unclear. This study attempts to reveal the pore structure of low permeability Eocene Liushagang Formation reservoir rocks from Weixinan and Wushi subbasins in Beibuwan Basin quantitatively and qualitatively using high pressure mercury intrusion porosimetry (HPMIP), N2 adsorption and field emission-scanning electronic microscopy (FE-SEM). Our results show that macropores (>50 nm) mainly contribute to the total pore spaces for most samples with lower shale content; mesopores(2–50 nm) dominate the pore spaces of samples with higher shale content, which leads to the relatively large surface area of these samples; permeability of these low permeability rocks is positively related with average pore-throat radius and negatively related with relative sorting coefficient while no such a close relationship exists between permeability and porosity; fractal dimension has a negative relationship with average pore-throat radius and permeability. In summary, this work comprehensively investigates the pore structure characteristics of low permeability Liushagang Formation reservoir rocks from Beibuwan Basin using multiple complementary approaches, which helps to further understand the hydrocarbon migration and accumulation mechanism of these low permeability reservoirs.

Influence of intrinsic permeability of reservoir rocks on gas recovery from hydrate deposits via a combined depressurization and thermal stimulation approach

Reservoir permeability is a crucial controlling factor for the successful exploitation of unconventional gas hydrate resources, which represent a vast natural gas reserve with substantial energy potential. Numerical simulations and analyses are essential tools for the prediction and evaluation of natural gas recovery from hydrate deposits. In this study, a two-dimensional axisymmetric model was developed and validated to investigate the effect of the intrinsic permeability of reservoir rocks on hydrate dissociation characteristics induced by a combined depressurization and thermal stimulation method. Simulation results indicate that the average gas production rate from hydrate deposits could be enhanced when thermal stimulation was additionally applied at the same production pressure, but the enhancement effect weakens as reservoir permeability increases. Pressure reduction propagates slowly from gas production wells into cores with low-permeability, and thermal stimulation dominates hydrate dissociation. However, depressurization can play a determining role for hydrate dissociation in high-permeability cores which benefit to the propagation of pressure reduction. Increased permeability promotes the characteristic shift from thermal-stimulation-governed radial hydrate dissociation to depressurization-determined uniform dissociation. To a certain extent, increased permeability enhances gas generation, but there is a threshold beyond which this effect is no longer felt as excessive consumption of sensible heat restricts further hydrate dissociation. Although there are many uncertainties in the hydrate dissociation process in porous media, numerical simulation can provide useful information for evaluating the feasibility of methodology for gas recovery from gas hydrate reservoirs.

An oil-based gel system for reservoir rock permeability modification

Water production during gas and oil recovery is a major problem for the oil industry, as the average worldwide production is more than five barrels of water per barrel of oil. Among the many attempted remedies, water-based polymers and cross-linked gels are often injected into the reservoir to control excessive water production. Recently, oil-based gelant systems have been proposed which are oil-soluble. These systems react with the reservoir water to form a rigid water-based gel during the shut-in period, thereby drastically reducing the permeability of the reservoir to water. The aim of this paper is to improve the understanding of how the flow of oil and water are affected by one of the oil-based gelant systems, TMOS. The gelation behaviour and gel characteristics were studied under static and dynamic conditions. Two-dimensional transparent glass models were used to study the effect of gelant flow, and evaluate the effectiveness of the gel in modifying the oil and water permeability. The ability of the gel to modify the water flow at different flow velocities yields a velocity-dependent permeability. New insights are presented that may help reservoir and production engineers to select and design better gel treatments for a given reservoir.

Spatial features of change of petrographic and reservoir properties of rocks of the Productive series (case study Guneshli field, South-Caspian basin)

In the paper on example of Guneshli field the South-Caspian basin the character of spatial changes of lithofacial parameters of the main oil-gas reservoir in Azerbaijan — productive series (Early Pliocene) has been considered. These studies were based on analysis of thin sections of different stratigraphic complexes of the productive series, the data of geophysical studies of the wells and as well as 3D geological modeling. Significant lithofacial changeability of productive series has been revealed both in section and in area that is explained by features of paleo-geographic conditions of sedimentation in early Pliocene and participation of various sources of feed of the basin with sediments. Dependence of initial yields of wells on spatial heterogeneity of permeability of reservoir rocks has also been established. It is established that spatial heterogeneity of lithofacial and reservoir properties of rocks controls their oil saturation and well productivity.

Investigation of effects of fracturing fluid on hydraulic fracturing and fracture permeability of reservoir rocks: An experimental study using water and foam fracturing

Hydraulic fracturing is a promising technique to enhance gas production from deep geological formations by enhancing reservoir rock permeability. However, permeability enhancement may vary with reservoir conditions and fracturing fluid. The main objective of this study is to investigate the effect of fracturing fluid on the fracture pattern and permeability of fractured rock. Fracturing experiments were conducted on siltstone specimens with water and foam (N2 + water) as the fracturing fluids, using a high-pressure triaxial apparatus. CT scanning and 3-D scanning technology were used to examine the fracture pattern and the fracture surface of the fractured specimens. The fractured specimens were then used to conduct permeability experiments for five different confining pressures (5 – 25 MPa) and six different injection pressures (1 – 6 MPa) with N2, and fracture permeability values were compared, based on the fracturing fluid type as well as the intact rock permeability. The results indicate that foam fracturing can induce a complex twisted fracture with greater surface area and the fracture is throughout the specimen. Moreover, foam fracturing emits more energy than water fracturing during the fracturing process, which is favourable for secondary fracture development. According to the measured permeability values, the fracture permeability of foam fractured specimens is about 5 × 105 times greater than that of intact and water-fractured specimens. With increasing confining pressure, N2 permeability decreases, regardless of the specimen (intact or fractured), and interestingly permeability decreases with increasing injection pressure. These observations are related to the effective stress principle and the Klinkenberg effect.

Insights into the radial water jet drilling technology – Application in a quarry

In this context, we applied the radial water jet drilling (RJD) technology to drill five horizontal holes into a quarry wall of the Gildehaus quarry close to Bad Bentheim, Germany. For testing the state-of-the-art jetting technology, a jetting experiment was performed to investigate the influence of geological heterogeneity on the jetting performance and the hole geometry, the influence of nozzle geometry and jetting pressure on the rate of penetration, and the possibility of localising the jetting nozzle utilizing acoustic activity. It is observed that the jetted holes can intersect fractures under varying angles, and the jetted holes do not follow a straight path when jetting at ambient surface condition. Cuttings from the jetting process retrieved from the holes can be used to estimate the reservoir rock permeability. Within the quarry, we did not observe a change in the rate of penetration due to jetting pressure variations. Acoustic monitoring was partially successful in estimating the nozzle location. Although the experiments were performed at ambient surface conditions, the results can give recommendations for a downhole application in deep wells.

Matrix permeability of reservoir rocks, Ngatamariki geothermal field, Taupo Volcanic Zone, New Zealand

The Taupo Volcanic Zone (TVZ) hosts 23 geothermal fields, seven of which are currently utilised for power generation. Ngatamariki geothermal field (NGF) is one of the latest geothermal power generation developments in New Zealand (commissioned in 2013), located approximately 15 km north of Taupo. Samples of reservoir rocks were taken from the Tahorakuri Formation and Ngatamariki Intrusive Complex, from five wells at the NGF at depths ranging from 1354 to 3284 m. The samples were categorised according to whether their microstructure was pore or microfracture dominated. Image analysis of thin sections impregnated with an epoxy fluorescent dye was used to characterise and quantify the porosity structures and their physical properties were measured in the laboratory. Our results show that the physical properties of the samples correspond to the relative dominance of microfractures compared to pores. Microfracture-dominated samples have low connected porosity and permeability, and the permeability decreases sharply in response to increasing confining pressure. The pore-dominated samples have high connected porosity and permeability, and lower permeability decrease in response to increasing confining pressure. Samples with both microfractures and pores have a wide range of porosity and relatively high permeability that is moderately sensitive to confining pressure. A general trend of decreasing connected porosity and permeability associated with increasing dry bulk density and sonic velocity occurs with depth; however, variations in these parameters are more closely related to changes in lithology and processes such as dissolution and secondary veining and re-crystallisation. This study provides the first broad matrix permeability characterisation of rocks from depth at Ngatamariki, providing inputs for modelling of the geothermal system. We conclude that the complex response of permeability to confining pressure is in part due to the intricate dissolution, veining, and recrystallization textures of many of these rocks that lead to a wide variety of pore shapes and sizes. While the laboratory results are relevant only to similar rocks in the Taupo Volcanic Zone, the relationships they highlight are applicable to other geothermal fields, as well as rock mechanic applications to, for example, aspects of volcanology, landslide stabilisation, mining, and tunnelling at depth.

Hydro-mechanical coupled mechanisms of hydraulic fracture propagation in rocks with cemented natural fractures

Natural fractures commonly exist in unconventional reservoirs such as shale and tight gas sandstone, which are mostly cemented (or sealed) with minerals and not able to contribute to reservoir storage or rock permeability. However, during hydraulic fracture stimulation, these cemented natural fractures will be encountered and influence hydraulic fracture geometry greatly and, thereby, gas production. In this work, hydraulic fracture propagation in rock with cemented natural fracture is investigated using our recently developed and validated hydro-mechanical coupled LBM-DEM model. The numerical results show that both the strength ratio (between cemented natural fracture and host rock) and the approach angle (between hydraulic and cemented natural fracture) significantly affect the hydraulic fracture propagation. A larger strength contrast or a smaller approach angle will be more conducive to deflection, which is consistent with experimental observation. For rocks with weakly cemented natural fractures, deflection is mainly caused by shear failure in weakly cemented fracture. However, for rocks with strongly cemented natural fractures, deflection happens accompanying with tensile failure in host rock along the cement wall, which cannot be captured by the previous numerical models where the cemented natural fracture is treated as a bonded interface. In addition, complex fracture network is more easily formed if multiple weakly cemented natural fractures are orthogonal to the hydraulic fracture propagation direction.

СУЧАСНІ ПІДХОДИ ДО ВИЗНАЧЕННЯ ПРОНИКНОСТІ ПОРІД-КОЛЕКТОРІВ ЗА ДАНИМИ ГЕОФІЗИЧНИХ ДОСЛІДЖЕНЬ

Permeability of rock is its physical property that describes its ability to conduct fluids under the pressure gradient. This paper presents short description and analysis of methods for determination of permeability of oil and gas reservoirs. Permeability is a function of different parameters that leads to difficulties during its estimation. Investigations of the void space structure of rocks, their anisotropy etc.were carried out in order to take into account all factors that have an influence on the permeability. Reservoir conditions could also be modeled for that purpose. Methods for determination of permeability of rocks can be divided into three groups: methods based on the laboratory studies of rocks; methods based on the well logging data; and methods based on the correlations between different parameters of rocks. The first two groups include methods for steady and unsteady fluid flow. Methods for the unsteady flow are usually more precise and rapid, thus prospects of extension of methods for permeability determination are mostly connected with them. Each of the presented methods to determine permeability is characterized by some pros and cons. The most appropriate method for the specific experiment is always chosen according to conditions and requirements and expected results. Further author's investigations will be related to the creation of petrophysical models of permeability of oil and gas reservoir rocks, including reservoirs of complex structure.

Permeability and Mineral Composition Evolution of Primary Seal and Reservoir Rocks in Geologic Carbon Storage Conditions

It has been reported that deep saline aquifers represent the largest geologic CO2 storage resource. To better predict containment effectiveness and long-term reservoir behavior of these formations, it is important to understand the potential geochemically induced changes to the porosity and permeability of both the primary sealing formation and CO2 storage formation rocks. To investigate these potential changes, an experimental study to probe the geochemical interactions of CO2/brine/rock system under geologic CO2 storage conditions was conducted in a static reaction system. Marine shale (primary sealing formation) and Lower Tuscaloosa sandstone (CO2 storage formation) core samples taken from the Plant Daniel CO2 storage test site (Jackson County, Mississippi) were exposed to CO2-saturated brine in a batch reactor at relevant geologic storage conditions (85°C and 23.8 MPa CO2 pressure) for 6 months. X-ray diffraction, scanning electron microscopy, computed tomography, and brine chemistry analyses were performed before and after the exposure. Permeability measurements from the marine shale and sandstone core samples before and after CO2/brine exposure indicated a significant effective permeability change. Sealing marine shale permeability increased following exposure while the permeability of the sandstone from the storage formation was observed to decrease. Analysis results of the primary sealing formation sample (marine shale) at the Plant Daniel CO2 storage test site have not been reported before. The permeability decrease of the Lower Tuscaloosa sandstone sample reported in this study verifies the results reported in a previous study. These results have implications for the integrity of the primary seal in a CO2 storage setting.