CO2 Reservoir Research Articles

Carbonated water injection under reservoir conditions; in-situ WAG-type EOR

Enriching injection water with CO2 has demonstrated promising results as a method for improving the oil recovery and securely storing CO2 in oil reservoirs. However, mutual interactions taking place between carbonated water and reservoir oil at elevated reservoir conditions are not fully understood. Herein, we present the results of a thorough and direct investigation of the interactions between live-oil/CO2/aqueous-phase leading to additional oil recovery and enhanced CO2 storage in pore-scale and core-scale.CO2 transfer from carbonated water to live oils can trigger liberation of light components in form of a new gaseous phase. This unique phenomenon would bring about higher degrees of oil swelling, and it can also create a three phase flow regime, which leads to effective reduction of residual oil saturation. The observations confirm that the performance of carbonated water injection (CWI) should be investigated under reservoir conditions using multi-components live oil and reservoir cores. From the core displacement tests, it was observed that secondary CWI could recover a significant amount of additional oil, which was 26% compared to conventional seawater injection. When CO2 content of injected CW (carbonated water) was halved, the oil recovery dropped by 1/3 Using live oils, it was found out that CO2 would be trapped in the new phase, which brings about an enhanced CO2 trapping mechanism. Under realistic reservoir conditions where complex mass transfer of CO2 from aqueous phase to oil and gas phases takes place, an “in-situ WAG-type” three-phase flow is generated with more effective sweep efficiency and pore-scale advantages.

Can Repetitive Small Magnitude-Induced Seismic Events Actually Cause Damage?

Geoengineering activities such as reservoir impoundment, mining, wastewater injection, geothermal systems, and CO2 capture have been linked directly to induced seismicity. With the industrial boom in natural shale gas production regions previously aseismic areas have seen an exponential growth in the frequency of small magnitude events, with multiple events observed in close proximity within a 24-hour time period. While the overwhelming majority of induced seismic research has focused on the causality, the potential risk posed to critical federal infrastructure has escaped scrutiny. This proposes the question, “Can repetitive small magnitude-induced seismic events actually cause damage?” A review of the potential risk is presented herein, concluding that a simplistic definitive statement of whether single or multiple small magnitude-induced seismic events do or do not cause damage to critical infrastructure cannot be justified, and warrants additional study. However, recent observations and research suggest the likelihood that these geoengineering-induced events can and do cause detrimental degradation of the subsurface (damaging the overlying structure) is not insignificant.

元坝含硫气井环空带压诊断方法与治理措施

环空带压现象在国内外高压气井中普遍存在，特别是高含H2S气井如果环空出现了异常压力，会影响到气井的安全生产，需要对气井环空异常压力进行诊断与治理。元坝长兴组属于高含H2S，中含CO2储层。本文结合元坝含硫气井的现场经验，对环空异常压力的诊断及判别方法进行了改进，并对含H2S套压异常井的环空保护液加注治理方案提供了新思路，以保障气井的安全、稳定生产，也为国内外环空带压气井的诊断与治理提供借鉴。 Annulus pressure is a common phenomenon in high pressure gas well at home and abroad, especially in wells with high H2S content if the annulus appeared abnormal pressure, safety production will affect the gas well and need diagnosis and treatment. The Changxing formation in Yuanba belongs to high H2S and medium CO2 reservoir. Based on the field experience of Yuanba, the diagnosis methods of abnormal pressure in annulus are improved, and a new idea for the treatment of annulus filling fluid with H2S casing pressure abnormal well is put forward. This ensures the safety and stable production of gas wells, and provides reference for the diagnosis and treatment of gas wells with annulus at home and abroad.

Experimental study on the interactions of supercritical CO2 and H2O with anthracite

ABSTRACTTo better understand the mechanism of interactions of supercritical CO2 (SCCO2) and H2O, untreated, SCCO2 treated and SCCO2-H2O treated anthracites were adopted to analyze changes in pore structure, adsorption capacity. Observations from experimental data reveal that mineral and other substances in the fractures and matrix of coal body are dissolved and mobilized by the carbonic acid formed from the mixture of SCCO2 and H2O, which may contribute to smaller pore development and enhance the adsorption capacity. These findings may provide new insights into effective and safe storage of CO2 in coal reservoir.

Gas-Water Two Phase Flow Simulation Based on Pore Network Model for Reservoir Rocks

The relative permeability and capillary pressure are essential to investigate fluid flow in porous media, in terms of studying seepage characteristics of gas -water for CO2 emission reduction through deep saline sequestration. In this paper, we presented gas -water phase flow numerical simulation based on pore network extractions of four rock samples. The influence of temperature, pressure and pore structure on relative permeability and capillary pressure were carefully investigated. Analysis of evaluated results demonstrated that pore structure has significant impact on relative permeability and capillary pressure both for gas/water drainage and imbibition cycles. However, the influence of temperature and pressure on relative permeability and capillary pressure for drainage cycle is neglect-able, while during the imbibition cycle, the gas phase relative permeability is decreasing with increasing pressure and temperature, while capillary pressure and wetting phase relative permeability are decreasing with increasing pressure and increasing with increasing temperature. That might cause by change of rock wetting behavior and interactions between fluid-gas-rock as temperature, pressure change which has more impact on gas flooding process than water flooding. After comparing numerical simulation results of drainage cycle based on Berea sandstone sample to the literature, it is seemed that numerical simulation based on pore network extractions is more efficient and economical method of studying seepage characteristics of gas -water at CO2 reservoir storage conditions.

Drilling into an active mofette: pilot-hole study of the impact of CO<sub>2</sub>-rich mantle-derived fluids on the geo–bio interaction in the western Eger Rift (Czech Republic)

Abstract. Microbial life in the continental deep biosphere is closely linked to geodynamic processes, yet this interaction is poorly studied. The Cheb Basin in the western Eger Rift (Czech Republic) is an ideal place for such a study because it displays almost permanent seismic activity along active faults with earthquake swarms up to ML 4.5 and intense degassing of mantle-derived CO2 in conduits that show up at the surface in form of mofettes. We hypothesize that microbial life is significantly accelerated in active fault zones and in CO2 conduits, due to increased fluid and substrate flow. To test this hypothesis, pilot hole HJB-1 was drilled in spring 2016 at the major mofette of the Hartoušov mofette field, after extensive pre-drill surveys to optimize the well location. After drilling through a thin caprock-like structure at 78.5 m, a CO2 blowout occurred indicating a CO2 reservoir in the underlying sandy clay. A pumping test revealed the presence of mineral water dominated by Na+, Ca2+, HCO3−, SO42− (Na-Ca-HCO3-SO4 type) having a temperature of 18.6 °C and a conductivity of 6760 µS cm−1. The high content of sulfate (1470 mg L−1) is typical of Carlsbad Spa mineral waters. The hole penetrated about 90 m of Cenozoic sediments and reached a final depth of 108.50 m in Palaeozoic schists. Core recovery was about 85 %. The cored sediments are mudstones with minor carbonates, sandstones and lignite coals that were deposited in a lacustrine environment. Deformation structures and alteration features are abundant in the core. Ongoing studies will show if they result from the flow of CO2-rich fluids or not.

Linking the local vertical variability of permeability and porosity to newly-interpreted lithofacies in the lower Mt. Simon CO2 reservoir

A full understanding of the subsurface processes relevant to CO2 geo-sequestration, including CO2 movement and trapping, requires establishing basic relationships between the sedimentary architecture in CO2 reservoirs and the associated variations in petrophysical attributes that can affect plume dynamics and residual CO2 trapping. In this context, the variance and covariance of petrophysical attributes of the lower Mt. Simon Sandstone reservoir (Illinois, USA) are quantitatively decomposed according to sedimentary textures and structures that vary among sedimentary facies. Building on Ritzi et al. (2016), the sedimentary facies of the lower Mt. Simon are re-classified with new interpretations of sedimentary structures. A newly-revised methodology is used in which factor interactions are formally quantified and the magnitude of their contribution to the variance is compared to the main-factor effects. The decomposition results show the main-factor effects contributing to the variance of permeability and porosity are the differences in grain-size and the presence or absence of bleaching textures. The differences in permeability or porosity among the newly defined sedimentary structures make a relatively small contribution to the sample variance, and the 2-way and 3-way factor interactions are negligible. Permeability and porosity increase with coarser grain size, independent of the presence or absence of bleaching and independent of sedimentary structure. The presence of bleaching textures reduces permeability and porosity independent of the grain size or sedimentary structure. The general approach and these specific results aid in developing parsimonious reservoir simulation models.

Impact of variation in multicomponent diffusion coefficients and salinity in CO2-EOR: A numerical study using molecular dynamics simulation

CO2 injection in depleted or partially depleted oil reservoirs entails a three phase flow system governed by physical processes such as molecular diffusion and solubility. Using numerical modelling, the aims of this paper are two-fold. (i) We investigate the impact of variations in the magnitude of diffusion of CO2 into oil on dissolution of CO2 in brine, and quantify the sensitivity of the simulation outputs (recovery factor and amount of CO2 stored in water and oil phases) by use of different sets of diffusion coefficients throughout the simulation based on the variations in the compositions of the fluids. (ii) We investigate whether CO2 dissolution in brine in a water-flooded system will be a competing or limiting factor for enhanced oil recovery by molecular diffusion of CO2 into oil. To this end, we use molecular dynamics (MD) simulation to determine composition-dependent diffusion coefficients for a multicomponent fluid system in a synthetic fractured reservoir that undergoes CO2 injection. In total we consider 5 components interacting in the reservoir model, namely, CO2, CH4, C4H10, C6H14 and C10H22. The fracture-matrix interaction is simplified with the dual-porosity assumption. Our results show that (i) molecular diffusion not only enhances oil recovery but also enhances CO2 dissolution in water. The enhancement, nevertheless, depends on the values of the multicomponent diffusion coefficients and may exhibit an optimal condition for dissolution due to the impact of CO2 diffusion and entrapment into matrix oil. (ii) The amount of CO2 stored in oil is strongly affected by variation in molecular diffusion coefficients (we observe up to %13 difference). (iii) The results show that there is 4% discrepancy between estimates of the recovery factor for simulation cases that are run with different values of diffusion coefficients. Therefore it is important to account for compositions-dependent diffusion coefficients in simulation of CO2-enhanced oil recovery processes.

Long‐Term Reaction Characteristics of CO2–Water–Rock Interaction: Insight into the Potential Groundwater Contamination Risk from Underground CO2 Storage

AbstractCO2 sequestration into saline aquifers is considered to be one of the most promising options for reducing industrial CO2 emissions to the atmosphere. However, there are still many uncertainties regarding the storage of CO2 in the subsurface because of a lack of knowledge about CO2–water–rock interaction within CO2 reservoirs and the potential risk of CO2 leakage. In this study, we construct a semi‐open type experimental system that can reproduce the interactions under conditions close to those of actual CO2 reservoirs. Using the system, we conduct CO2–water–rock interaction experiments for 8 months to monitor the long‐term reaction and the mobilization of harmful metal elements. Altered tuffaceous rock is used in the experiment because these tuffaceous rock formations (called “Green Tuff”) are a potential candidate for CO2 storage in Japan. The results show that the major‐element water composition will converge to the point where host rock dissolution and secondary mineral precipitation are balanced; then, the interaction will proceed under a certain groundwater composition. In addition, we found that groundwater contamination by some metal elements (Ni, Ba, and Mn) may reach unsafe levels for drinking water as a result of CO2‐water–rock interaction.

Quantification of oil recovery efficiency, CO2 storage potential, and fluid-rock interactions by CWI in heterogeneous sandstone oil reservoirs

Significant interest exists in improving recovery from oil reservoirs while addressing concerns about increasing CO2 concentrations in the atmosphere. The combination of Enhanced Oil Recovery (EOR) and safe geologic storage of CO2 in oil reservoirs is appealing and can be achieved by carbonated (CO2-enriched) water injection (CWI). So far, through several flooding experiments, the potential of carbonated water injection as an EOR scenario has been investigated. While several coreflood experiments on homogeneous cores have been performed, there is no information on the effectiveness of CWI for oil recovery and CO2 storage potential on heterogeneous cores. Since not all the oil reservoirs are homogenous, understanding the potential of CWI as an integrated EOR and CO2 storage scenario in heterogeneous oil reservoirs is essential.With this objective, a series of high-pressure and high-temperature coreflood experiments were performed on a heterogeneous sandstone core. Based on the results, the heterogeneity of rock dominated water and carbonated water flow paths led to early breakthrough. However, interestingly, the ultimate oil recovery by CWI, either as the secondary or tertiary injection scenario, was higher than that of conventional waterflooding. Both secondary and tertiary CWI showed a strong potential for increasing oil recovery from the heterogeneous core and re-mobilized part of the trapped oil. In addition to the strong oil recovery by CWI, CWI demonstrated the good potential for safe underground storage of CO2 in heterogeneous reservoirs. Furthermore, carbonated water-sandstone rock interactions led to the slight mineral dissolution of the rock and separation of the submicron inorganic particles from the surface of the rock. These inorganic particles, which were previously interacting with asphaltenes and polar components of the oil during the ageing period, produced a hydrogen bond with water and formed oil in water emulsion. This phenomenon is called “Pickering emulsion” which can lead to wettability alteration from oil-wet towards more water-wet conditions and in turn a better oil recovery by CWI.

Nonlinear acoustics evaluation of CO2 exposed sandstone

In an effort to better understand the hygro-thermo-mechanical behavior of geologic CO2 reservoir material, we investigate the non-linear behavior of elastic wave propagation in Berea sandstone samples, which are used as a standard for reservoir rock formations. Nonlinear characterization methods, including resonant ultrasound spectroscopy (RUS), dynamic acousto-elasticity (DAET), and single-impact nonlinear resonance techniques, are applied to pristine, damaged (distributed microfractures), and CO2 injected Berea samples; conventional linear vibrational and wave propagation measurements are also applied to the samples. The results of these sensitive test methods are compared to reveal the characteristics of geologic reservoir materials that are most affected by varying microstructural and environmental conditions. An analysis of the work also leads to potential bases for test methods that could be deployed in the field in the future to monitor the condition of reservoir formations and lead to better under...

Evaluating model complexity in simulating supercritical CO2 dissolution, leakage, footprint, and reservoir pressure for three-dimensional hierarchical aquifer

A hierarchical fully heterogeneous aquifer model (FHM) provides a reference for developing and testing 3 facies-based hydrostratigraphic models (HSMs) each representing a CO2 storage aquifer with reduced permeability (k) heterogeneity resolution: 8-unit, 3-unit, and 1-unit homogeneous models. Under increasing aquifer lnk variances (0.1, 1.0, 4.5), flow upscaling was conducted to calculate equivalent permeabilities for the HSMs. Within a Design of Experiment uncertainty analysis framework varying geothermal gradient, salinity of formation water, caprock permeability, and injection rate, CO2 injection coupled to convective mixing was simulated by all models. In addition to the injection phase, all simulations were carried out for 2000 years using PFLOTRAN, a massively parallel, multiphase, multicomponent numerical simulator that ran on the NCAR-Wyoming Supercomputing Center's Yellowstone supercomputer. Simulation outcomes of the HSMs were compared to those of the FHM within their full parameter space, and four performance metrics were evaluated: dissolved CO2, CO2 leakage, plume footprint, and pore pressure evolution in response to injection and migration. Results suggest that aquifer variance, heterogeneity resolution, and salinity can all affect the development of fingering and convective mixing, and therefore the amount of dissolution storage. For the modeling choices and assumptions made in this study, the 3-unit HSM was found to be an all-around optimal model by capturing both the sensitivity of the FHM and the performance metrics under different reservoir storage or operational conditions. Implications for modeling long-term CO2 storage in data-poor systems are discussed and future research indicated.

Causes of abundant calcite scaling in geothermal wells in the Bavarian Molasse Basin, Southern Germany

The carbonate-dominated Malm aquifer in the Bavarian Molasse Basin in Southern Germany is being widely exploited and explored for geothermal energy. Despite favorable reservoir conditions, the use of geothermal wells for heat and power production is highly challenging. The main difficulty, especially in boreholes >3000m deep with temperatures >120°C, is that substantial amounts of calcite scales are hindering the proper operation of the pumps within the wells and of the heat exchangers at the surface. To elucidate the causes of scaling we present an extensive geochemical dataset from the geothermal plant in Kirchstockach. Based on chemical analyses of wellhead water samples, chemical and mineralogical analyses of scales collected along the uppermost 800m of the production well, and chemical analyses of gas inclusions trapped in calcite-scale crystals, four processes are evaluated that could promote calcite scaling. These are (i) decompression of the produced fluid between the reservoir and the wellhead, (ii) corrosion of the casing that drives pH increase and subsequent calcite solubility decrease, (iii) gas influx from the geothermal reservoir and subsequent stripping of CO2 from the aqueous fluid, and (iv) boiling within the geothermal well. The effectiveness of the four scenarios was assessed by performing geochemical speciation calculations using the codes TOUGHREACT and CHILLER, which explicitly simulate boiling of aqueous fluids (CHILLER) and take into account the pressure dependence of calcite solubility (TOUGHREACT). The results show that process i causes notable calcite supersaturation but cannot act as the sole driver for scaling, whereas ii and iii are negligible in the present case. In contrast, process iv is consistent with all the available observations. That is, scaling is controlled by the exsolution of CO2 upon boiling at the markedly sub-hydrostatic pressure of 4–6bar within the production well. This process is confirmed by the visible presence of gas inclusions in the calcite scales above the downhole pump, where the production fluid should nominally have been in the homogeneous liquid state. Whereas minor calcite scaling may have been triggered by fluid decompression within the production well, we conclude that the abundant scaling along the pump casing is due to cavitation induced by operating the pump at high production rates.

GEOCHEMICAL MODELING FOR THE ASSESSMENT OF THE CO2 STORAGE POTENTIAL IN THE MESOHELLENIC TROUGH, NW GREECE

Sandstone of the Pentalofos formation from the Mesohellenic Trough was examined as a potential reservoir for CO2 sequestration. Experiments were carried out into batch reactors for 6 months by mixing a simplified porewater solution saturated with CO2 (150 bar, 70oC) with crushed sandstone. The sandstone is mainly composed of carbonates, feldspars and quartz, and secondly of clays and phyllosilicates. Chemical analysis of aqueous samples showed an increase in the concentration of dissolved ions as the experiment progressed. Geochemical kinetic models that were constructed using the PHREEQC geochemical code showed that the fluid chemistry is controlled by carbonate and feldspar dissolution, clay and quartz precipitation and cation exchange reactions. The proposed models were also used to estimate the future changes in mineralogy of the sandstone in order to evaluate its suitability as a CO2 reservoir.

Carbon footprints of two large hydro-projects in China: Life-cycle assessment according to ISO/TS 14067

Hydropower offers significant potential for reductions in carbon emissions. Nevertheless, the past two decades witnessed growing worldwide concerns about excessive greenhouse gas (GHG) emissions by damming and reservoir creation. Carbon footprint of a hydro-project within its full life-cycle is scientifically reasonable to evaluate the climate impact of hydropower. Located in the upper course of the Yangtze River, the Xiluodu (XLD) and Xiangjiaba (XJB) dams are the second and third largest hydro-projects in China. Following ISO/TS 14067, system boundary of the life-cycle assessments included pre-impoundment clearance, construction, reservoir operation, maintenance and dam decommission. GHG emissions from different land cover in flooded area are specially considered to estimate reservoir net GHG emissions. The life-cycle GHG emissions of the XLD and XJB hydro-projects are 7.60 ± 1.09 gCO2eq/kWh and 9.12 ± 1.36 gCO2eq/kWh, respectively. Reservoir CH4 and CO2 emissions and the potential release of CH4 from sediment in phase of dam decommission are the most sensitive factors. Through direct allocation of life-cycle GHG emissions according to water consumption, 95.9% and 97.2% of the emissions in XLD and XJB are allocated to hydropower. In comparison with global cases, energy payback and life-cycle GHG emissions of both hydro-projects were competitive, supporting excellent environmental and energy performances.

Flue gas injection for EOR and sequestration: Case study

The combination of carbon dioxide enhanced oil recovery (CO2-EOR) and permanent CO2 storage in mature oil reservoirs has the potential to provide a critical near-term solution for reducing greenhouse gas (GHG) emissions. This solution involves the combined application of carbon capture and storage from power generation and other industrial facilities with CO2-EOR. In order to reduce CO2 capture costs flue gas, which consists mainly of N2 and CO2, injection has been proposed. The main aim of this research is to investigate flue gas injection in a mature oil field located in Turkey where CO2 EOR had been applied between 2003 and 2012. Injected CO2 was produced from a nearby small natural CO2 reservoir with limited resource. Due to the availability of nearby flue gas source (cement factory) and a pipeline for gas transportation, which was built to transport natural gas from the oil field to cement factory, there is a huge opportunity to decrease project costs. A 3D compositional simulation model was built after a detailed fluid characterization. After history matching 31 years of production, injection, saturation and pressure history, a comparative study was conducted to examine the efficiency of flue gas injection compared to CO2 injection for simultaneous EOR and storage purposes. Storage capacity of the oil field as well as the contribution of raw flue gas injection and CO2 injection to oil recovery were studied. Effect of injected gas type, gas solubility and operating parameters on storage and recovery were investigated. Results showed that pure CO2 injection leads to higher oil recovery and CO2 storage, if injection continued for at least 25 years. Before this threshold injection time, flue gas injection and pure CO2 injection resulted in comparable oil recoveries. It was also concluded that pressurizing the reservoir with raw flue gas injection followed by pure CO2 injection may improve the project economics.

Impact of Solid Surface Energy on Wettability of CO2-brine-Mineral Systems as a Function of Pressure, Temperature and Salinity

CO2 storage refers to the methods employed to inject CO2 in depleted oil and gas reservoirs and deep saline aquifers for long term storage of CO2 with the objective to reduce the anthropogenic CO2 emissions. Wettability and interfacial tension are two important multiphase parameters which are used to characterize the flow behavior of CO2 in reservoirs. Numerous studies have reported wettability data of CO2-brine systems on various rock forming minerals as function of pressure, temperature and salinity. However, the associated trends have not been physically well-understood and require considerable attention which is objective of our present work.In this work, we apply Neumann's equation of state method to our measured contact angle data for CO2-brine-mica systems and contact angle data of CO2-brine-quartz from Sarmadivaleh et al., 2015.Our results indicate that for mica, solid-CO2 interfacial tension decrease with pressure and salinity and increase with temperature. Moreover, solid-liquid interfacial tension decrease with temperature and decrease with salinity. For quartz, although the solid-CO2 interfacial tension decrease with pressure and increase with temperature, yet solid-liquid interfacial tension increase with temperature which explains the increase in contact angle with temperature for quartz. Overall, we find that results are in accordance with wettability data as function of pressure, temperature and salinity. We thus conclude that hotter reservoirs with lower injection pressure and lower brine salinities exhibit relatively better water wetting state and hence better seal capacity leading to higher CO2 storage potential. We also conclude that solid surface energy approach adequately explains the dependency of wettability on pressure, temperature and salinity.

Availability of a Simplified Coarse Grid Model for History Matching at the Nagaoka Post-injection CO2 Monitoring Site

The Nagaoka site is known as the place where the post-injection monitoring has been conducted over 10 years. During post-injection period, fluid samples were collected from the CO2 reservoir twice. The concentration of dissolved species, such as pH, Ca, and carbonates, were obtained to investigate progress of geochemical reactions between CO2 and the reservoir. In addition, a reactive transport modelling with a simplified coarse grid model has also conducted to understand behavior of CO2 in the reservoir. We succeed in explaining that the reservoir has the ability of neutralization against CO2 disturbance and of mineral trapping of CO2 as calcite.

Analysis of a Complex Faulted CO2 Reservoir Using a Three-dimensional Hydro-geochemical-Mechanical Approach

This work applies a three-dimensional (3D) multiscale approach recently developed by Nguyen et al. (Int. J. Greenhouse Gas Control, 2016, 46:100-115; Greenhouse Gases: Sci. & Technol., DOI: 10.1002/ghg.1616) to analyze a complex CO2 faulted reservoir that includes some key geological features of the San Andreas and nearby faults. The approach couples the STOMP-CO2-R code for flow and reactive transport modeling to the ABAQUS® finite element package for geomechanical analysis. The objective is to examine the coupled hydro-geochemical-mechanical impact on the risk of hydraulic fracture and fault slip in a complex and representative CO2 reservoir that contains two nearly parallel faults. STOMP-CO2-R/ABAQUS® coupled analyses of this reservoir are performed assuming extensional and compressional stress regimes to predict evolutions of fluid pressure, stress and strain distributions as well as potential fault failure and leakage of CO2 along the fault damage zones. The tendency for the faults to slip and pressure margin to fracture are examined in terms of stress regime, mineral composition, crack distributions in the fault damage zones and geomechanical properties. This model in combination with a detailed description of the faults helps assess the coupled hydro-geochemical-mechanical effect.

Capillary Limited Flow Behavior of CO2 in Target Reservoirs in the UK

The flow of supercritical CO2 and brine in the subsurface is predicted to be strongly dependent on both the fluid properties and the heterogeneity of the pore space. However there are few laboratory studies that characterise the interaction between fluid properties and heterogeneity in real reservoir rocks. We explore the sensitivity of CO2 flow paths and relative permeability to pore space capillary heterogeneity in target CO2 storage reservoirs in the UK and Australia. Samples from potential North Sea and East Irish Sea reservoirs and a current CO2 storage site in Australia are compared. The rock samples are all of high permeability (>500mD) and porosity (>12%), and are clean and homogeneous sandstones. Relative permeability is found to be highly sensitive to minor heterogeneities in pore structure at reservoir conditions that give rise to a low CO2 viscosity and in particular when the flow is capillary limited, as will be the case for most of the reservoir. We use a simple capillary number in guiding the measurement of relative permeability and residual trapping under viscous and capillary limited conditions. Observations suggest that to fully characterise the behaviour in a reservoir a range of relative permeability curves must be measured which can be applied as the flow of CO2 slows with distance from the near wellbore and flow behaviour changes from viscous-dominated to capillary-dominated. Experiments are performed at 8-20 MPa, 40-90°C and brine molalities of 0 – 5 mol/kg NaCl. Saturation is measured in situ, using a medical x-ray CT scanner, which allows the fluid arrangement to be observed at a resolution of 0.25x0.25x1 mm.