CO2 Geosequestration Research Articles

Modeling CO2 wettability behavior at the interface of brine/CO2/mineral: Application to CO2 geo-sequestration

Carbon capture and storage (CCS) has been introduced as an effective method for reduction of CO2 emissions to the atmosphere. While different aspects and controlling parameters of geological CO2 sequestration process are well understood, there is still large uncertainty regarding brine/CO2/rock wettability and no model has yet been presented for characterizing the contact angle of brine/CO2/rock system at different environmental conditions. In this study, various intelligent models have been developed for accurate estimation of brine/CO2/rock contact angles. Results demonstrated that the proposed models have the ability to accurately simulate the brine/CO2 wettability behavior for quartz, calcite, feldspar, and mica minerals at different pressures, temperatures and salinities. Additionally, results revealed that adaptive neuro-fuzzy interference system has the best performance compared with the other models and its superiority is shown through statistical and graphical analyses. Afterward, the most effective input parameters on brine/CO2/rock wettability were investigated by employing Monte-Carlo algorithm, which showed that mineral type, salinity and pressure are the most sensitive variables for this process. As wettability can highly affect the residual and structural trapping mechanisms during carbon geo-sequestration, presenting reliable models for estimating brine/CO2/rock wettability is crucial. Therefore, the outcomes of this study can be useful for accurate estimation of these mechanisms capacity.

Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study

Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.

A new methodology to assess the maximum CO2 geosequestration capacity of shale reservoirs with SRV based on wellbore pressure

Shale reservoirs are promising geological sites for CO2 storage due to their high total organic content (TOC) and the large-scale hydraulic fracturing operations. In order to critically evaluate a potential storage reservoir, fast, robust tools are needed to assess the CO2 storage capacity. Based on our previous work, an efficient method based on semi-analytical solution for calculating the maximum CO2 storage capacity in shale formations is derived, based on the injection wellbore pressure. The new methodology fully reflects the flow, diffusion, and adsorption processes of CO2 in shales. It also simulates natural fractures, hydraulic fractures, and the stimulated reservoir volume (SRV). The semi-analytical solution utilizing a Laplace transform and Stehfest numerical inversion is developed to evaluate the wellbore pressure and storage capacity in shale formations, which is verified using numerical simulations. A case study of the derived method on the Bakken Shale shows that the CO2 storage capacity is strongly controlled by the CO2 injection rate, adsorption index, and storage ratio. It is also found that the effective diffusion coefficient and mobility ratio affect the CO2 storage capacity during different periods of the CO2 storage process.

Probing the 3D molecular and mineralogical heterogeneity in oil reservoir rocks at the pore scale

Innovative solutions have been designed to meet the global demand for energy and environmental sustainability, such as enhanced hydrocarbon recovery and geo-sequestration of CO2. These processes involve the movement of immiscible fluids through permeable rocks, which is affected by the interfacial properties of rocks at the pore scale. Overcoming major challenges in these processes relies on a deeper understanding about the fundamental factors that control the rock wettability. In particular, the efficiency of oil recovery strategies depends largely on the 3D wetting pattern of reservoir rocks, which is in turn affected by the adsorption and deposition of ‘contaminant’ molecules on the pores’ surface. Here, we combined high-resolution neutron tomography (NT) and synchrotron X-ray tomography (XRT) to probe the previously unobserved 3D distribution of molecular and mineralogical heterogeneity of oil reservoir rocks at the pore scale. Retrieving the distribution of neutron attenuation coefficients by Monte Carlo simulations, 3D molecular chemical mappings with micrometer dimensions could be provided. This approach allows us to identify co-localization of mineral phases with chemically distinct hydrogen-containing molecules, providing a solid foundation for the understanding of the interfacial phenomena involved in multiphase fluid flow in permeable media.

Immiscible fluid displacement in porous media with spatially correlated particle sizes

Immiscible fluid displacement in porous media is fundamental for many environmental processes, including infiltration of water in soils, groundwater remediation, enhanced recovery of hydrocarbons and CO2 geosequestration. Microstructural heterogeneity, in particular of particle sizes, can significantly impact immiscible displacement. For instance, it may lead to unstable flow and preferential displacement patterns. We present a systematic, quantitative pore-scale study of the impact of spatial correlations in particle sizes on the drainage of a partially-wetting fluid. We perform pore-network simulations with varying flow rates and different degrees of spatial correlation, complemented with microfluidic experiments. Simulated and experimental displacement patterns show that spatial correlation leads to more preferential invasion, with reduced trapping of the defending fluid, especially at low flow rates. Numerically, we find that increasing the correlation length reduces the fluid-fluid interfacial area and the trapping of the defending fluid, and increases the invasion pattern asymmetry and selectivity. Our experiments, conducted for low capillary numbers, support these findings. Our results delineate the significant effect of spatial correlations on fluid displacement in porous media, of relevance to a wide range of natural and engineered processes.

Qualitative and quantitative evaluation of the alteration of micro-fracture characteristics of supercritical CO2-interacted coal

CO2 geo-sequestration necessitates injection of CO2 into coal reservoirs, in which CO2 becomes supercritical due to high pressure/temperature conditions. Consequently, the coal-supercritical CO2 (S−CO2) interaction triggers micro-structural alterations, inferring the necessity of temporal and spatial analyses. In this study, three imaging techniques were used to evaluate the S−CO2-induced micro-structural alterations in heterogeneous coal specimens. Results from the qualitative analysis indicate that S−CO2 interaction causes new fracture formation and extension/widening of existing fractures in coal. Quantitative analysis concludes that fracture fraction and fracture-matrix interface area increase linearly with S−CO2 interaction time. Spatial disposition of mineral/maceral phases at specific arrangements significantly affects the induced fracture geometry, where most of the fractures form at mineral-maceral interfaces, parallel to mineral layering. Comparison of S−CO2 interaction under unconstrained and constrained conditions reveals that S−CO2-induced micro-fracture alterations have both similarities and dissimilarities, due to specific swelling mechanisms.

Rapid gas transport in the near-surface of the earth

Conventional models of gas transport in the earth centres on diffusion, convection and advection. Anecdotal and experimental evidence suggests that sometimes gas transport can be orders of magnitude faster. A model of microbubble transport with vertical velocities of the order of 1 - 1000 m/day, dependant on microfracture size, provides a mechanism for these observations. Because the force acting on a microbubble is buoyancy, the flow will be vertical with little dispersion. This presentation will review this theory and some of the tests conducted to confirm such rapid vertical velocities. Fast gas transport also has applications. For example, radon (222Rn, t½ = 3.8 days) is often used for locating uranium but can only work with rapid movement of a carrier gas. Radon has also been used for fault location. Measurement of radon gas flux on the surface has also been used to locate in-situ fires in coal seams in the Hunter Valley, fires which are located at 300 ? 450m depth. Whether the radon is from the source (burning coal) or picked up by the flowing gas (CO2), the surface measurements of radon show an anomaly located vertically over the fires and which may then be used to locate such events. The occurrence of rapid gas movement gives cause for concern over geosequestration of CO2 as zones of high flux must be mapped and avoided.

Seismic monitoring of CO2 Geosequestration: CO2CRC Otway project case study

The CO2CRC Otway Project is Australia?s first demonstration of the deep geological storage of carbon dioxide. Its test site is located in Victoria, onshore. Within the bound of the first phase of the Otway project ~61000 tonnes of CO2/CH4 mixture were injected into depleted gas reservoir located at a depth of 2 km. Second phase of the project is dedicated to injection of small amount (up to 10 000 tonnes) of CO2-rich gas to saline aquifer at depth of ~1.3 km. Time-lapse seismic is a powerful tool for imaging of changes in the subsurface such as migration of CO2 within reservoir and assurance monitoring of possible leakage to other formations. However imaging of gas-into-gas injection (phase I) or injection of very small amounts (phase II) using land seismic are complicated problems. To meet these challenges a comprehensive seismic program is developed and being implemented. It includes surface and borehole time-lapse seismic surveys. First 3D survey was acquired in year 2000 to find gas fields in the area, two more surveys were shot in 2008 (pre-injection baseline) and 2009 (first monitor, ~31 000 tonnes of gas were injected to the date of survey), next survey is scheduled at January, 2010. A number or repeated 2D surveys were acquired over last several years to optimize 3D seismic acquisition technique and investigate repeatability of land seismic data.

The stratigraphic significance of paralic deposits in the Precipice–Evergreen succession, Surat Basin, Queensland

The Precipice Sandstone and Evergreen Formation in the Surat Basin, Queensland, are being examined as a reservoir-seal option for future geosequestration of CO2. Effective reservoir modelling, and prediction of dynamic storage capacity, however, depends upon accurate depositional interpretations relating to an understanding of the stratigraphic architecture. Throughout most of the basin, the Precipice Sandstone is generally considered to have good reservoir properties and lateral continuity. Refined depositional models and a widely-applied sequence stratigraphic framework will enhance prediction of the most prospective play segments for CO2 injection. We utilize integrated ichnological-sedimentological facies analysis from core to interpret the Precipice Sandstone as a braided fluvial to braid-delta succession, overlain by lower delta plain to subaqueous delta and estuarine embayment deposits of the Evergreen Formation. Facies successions and core-calibrated wireline logs show brackish-water influenced deposits at several stratigraphic intervals. Brackish-water influenced deposits overlie upper delta plain or braid-plain sediments. They occur laterally adjacent to subaerial lower delta plain strata, and generally cap parasequence-sets. Seismic surveys resolve lower-order cyclicity, showing parasequence-sets within the Precipice succession that retrograde or aggrade and onlap the basal-Surat unconformity. This stratal arrangement reflects the lowstand and early transgressive systems tracts of a 2rd order depositional sequence or a distinct 3th order sequence. Late transgressive and early highstand systems tracts are more abundant within the lower Evergreen Formation and are interpreted to consist of restricted or estuarine central basin deposits; but these may also represent a 3th order sequence. Additional chronometric data is needed to differentiate between these interpretations. Depositional and sequence stratigraphic interpretations suggest the Precipice Sandstone has a higher degree of heterogeneity than previously appreciated. Moreover, we show that the Evergreen Formation is not a simple basin-wide sealing unit due to the presence of sandstone geobodies that complexly cross-cut each other (i.e., the ‘Boxvale Sandstone Member’) that may act as vertical fluid conduits. The sequence stratigraphic characteristics of the reservoir-seal pair should be carefully considered when selecting locations for CO2 sequestration.

Visualization of hydrate formation during CO2 storage in water-saturated sandstone

Formation of solid CO2 hydrates during geosequestration of CO2 may offer increased storage capacity and provide extra sealing in cold aquifers. Evaluation of the integrity and distribution of the formed hydrate seal requires comprehensive knowledge about the CO2 flow and hydrate growth pattern within sedimentary pores. We address this knowledge gap by pore- to core-scale visualization of hydrate formation during liquid CO2 injection in water-filled sandstone (P = 70 bar, T = 1–2 °C). Pore-level hydrate growth is analyzed by direct imaging of the pore space in a micromodel chip that is an analog to the pore network in a sandstone. Flow visualization of CO2-water drainage followed by hydrate formation is also presented at core-scale in Bentheim sandstone using high-field MR imaging. The image results verified hydrate nucleation both at the liquid-liquid interface and in the water phase alone due to the presence of dissolved CO2. The pore-filling hydrate growth pattern effectively reduced the sandstone permeability and showed the potential of CO2 hydrate as a sealing mechanism during CO2 sequestration.

Alterations of geochemical properties of a tight sandstone reservoir caused by supercritical CO2-brine-rock interactions in CO2-EOR and geosequestration

The geochemistry of a reservoir is of great significance for CO2 Enhanced Oil Recovery (CO2-EOR) and CO2 geosequestration operations. However, due to the massive diversity in mineralogy and physicochemistry of different reservoirs, the current data base is not yet sufficient to conclusively determine the alterations of geochemical prosperities when CO2 is injected especially for tight reservoirs. The attention of this work was given to a tight sandstone reservoir in Lucaogou formation of Jimsar sag (China). The interactions of reservoir rocks, formation brine and supercritical CO2 were extensively investigated under reservoir conditions (75 °C and 32 MPa) aiming to reveal possible mechanisms behind. The results showed that the dissolution of supercritical CO2 in the brine created an acidic environment (solubility = 0.94 mol/Kg), which induced the dissolution of minerals into the brine and their subsequent precipitation. The primary precipitants in this work were found to be iron minerals and kaolinite, as evidenced by Scanning Electron Microscopy and Energy Dispersion Spectrum (SEM-EDS) analyses. Moreover, the SEM-EDS observations have shown clear signs of mineralogical changes of the rocks with the preferred dissolution of K-feldspar, albite and ankerite. Kaolinitation due to the corrosion of K-feldspar and albite occurred during the CO2-exposure experiments. The mineral surface after exposure to CO2 was altered to be more water-wet as a result of mineral dissolution, kaolinite formation and surface corrosion.

The effect of WACO2 ratio on CO2 geo-sequestration efficiency in homogeneous reservoirs

Various factors such as reservoir temperature, wettability, caprock properties, vertical to horizontal permeability ratio, salinity, reservoir heterogeneity, injection well configuration affect the CO2 geo-sequestration efficiency. Furthermore, it was previously investigated that CO2 storage efficiency can be improved by using water alternating CO2 (WACO2) technology. However, the effect of the WACO2 ratio (the ratio of the total amount of injected CO2 to the total amount of injected water) on CO2 storage efficiency has not been addressed adequately. Thus, in this paper, a 3D homogeneous reservoir simulation model has been developed to study the impact of the WACO2 ratio on CO2 mobility and CO2 trapping capacity using five different WACO2 ratios (i.e. 3, 2, 1, 1/2, and 1/3). For all WACO2 ratios tested, 9000 kton (kt) of CO2 were injected during 3 CO2 injection cycles (2 years each) and at an injection rate of 1500 kt per year. Each CO2 injection cycle was followed by a 2 years water injection cycle with injection rates of 500 kt/year, 750 kt/year, 1500 kt/year, 3000 kt/year, and 4500 kt/year for the 3, 2, 1, 1/2, and 1/3 WACO2 ratios, respectively. Then, this 12 years WACO2 injection period was followed by a 100 years post-injection period. Our results clearly indicate, after 100 years post-injection period, that the WACO2 ratio has an important effect on the CO2 migration distance, CO2 mobility and CO2 trapping capacity. The results demonstrate that lower WACO2 ratio leads to reduce the vertical CO2 plume migration and CO2 mobility. Furthermore, low WACO2 ratio enhances the capacities of capillary and solubility trapping mechanisms. Thus, we conclude that WACO2 has a significant impact on the geo-sequestration efficiency and less WACO2 ratios are preferable

Mapping a coastal transition in braided systems: an example from the Precipice Sandstone, Surat Basin

ABSTRACTThe Precipice Sandstone is traditionally interpreted as a braided fluvial deposit that transitions upwards into meandering channel deposits responding to a rise in base level that eventually deposits the overlying alluvial to lacustrine Evergreen Formation. This study found sedimentary evidence of tidal to marine influence within the Precipice Sandstone coincident with avulsion and diversion of the system from southward to northward-flowing channels as the system was transgressed. The north-flowing channels are interpreted to debouch into a shallow restricted marine embayment with tide and wave influence, which provides an alternative insight into this unit and suggests a Lower Jurassic north or northeasterly marine connection. The Precipice Sandstone is a regional aquifer, in places hosts hydrocarbons and has been considered as a storage unit for CO2 geosequestration. Outcrop analogues can provide geometries to accompany facies interpreted from sedimentary structures that are observable in core, to assist in characterising reservoir heterogeneity.

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.

Development of a hydraulic stimulation simulator toolbox for enhanced geothermal system design

Abstract Hydraulic stimulation is the key technology in the enhanced geothermal system (EGS) development. In this study, a reservoir stimulation simulator toolbox was developed for the comprehensive EGS design considering the natural fracture distribution, borehole stability, hydraulic stimulation and the thermal performance of the reservoir. The toolbox program consists of five modules, i.e., 3D discrete fracture network (DFN) generation, borehole stability analysis, hydrofracturing estimation, hydroshearing estimation and reservoir temperature prediction. Each module is implemented with graphic user interface using MATLAB® and available as a stand-alone program. The program allows independent analysis of each module and combined analyses with compatible data among the related modules, which provides extensive applicability to a variety of tasks associated with EGS stimulation, shale gas fracturing and CO2 geosequestration.

A Monte Carlo approach to constraining uncertainties in modelled downhole gravity gradiometry applications

Gravity gradiometry has a long legacy, with airborne/marine applications as well as surface applications receiving renewed recent interest. Recent instrumental advances has led to the emergence of downhole gravity gradiometry applications that have the potential for greater resolving power than borehole gravity alone. This has promise in both the petroleum and geosequestration industries; however, the effect of inherent uncertainties in the ability of downhole gravity gradiometry to resolve a subsurface signal is unknown. Here, we utilise the open source modelling package, Fatiando a Terra, to model both the gravity and gravity gradiometry responses of a subsurface body. We use a Monte Carlo approach to vary the geological structure and reference densities of the model within preset distributions. We then perform 100 000 simulations to constrain the mean response of the buried body as well as uncertainties in these results. We varied our modelled borehole to be either centred on the anomaly, adjacent to the anomaly (in the x-direction), and 2500 m distant to the anomaly (also in the x-direction). We demonstrate that gravity gradiometry is able to resolve a reservoir-scale modelled subsurface density variation up to 2500 m away, and that certain gravity gradient components (Gzz, Gxz, and Gxx) are particularly sensitive to this variation in gravity/gradiometry above the level of uncertainty in the model. The responses provided by downhole gravity gradiometry modelling clearly demonstrate a technique that can be utilised in determining a buried density contrast, which will be of particular use in the emerging industry of CO2 geosequestration. The results also provide a strong benchmark for the development of newly emerging prototype downhole gravity gradiometers.

Stabilising nanofluids in saline environments

Nanofluids (i.e. nanoparticles dispersed in a fluid) have tremendous potential in a broad range of applications, including pharmacy, medicine, water treatment, soil decontamination, or oil recovery and CO2 geo-sequestration. In these applications nanofluid stability plays a key role, and typically robust stability is required. However, the fluids in these applications are saline, and no stability data is available for such salt-containing fluids. We thus measured and quantified nanofluid stability for a wide range of nanofluid formulations, as a function of salinity, nanoparticle content and various additives, and we investigated how this stability can be improved. Zeta sizer and dynamic light scattering (DLS) principles were used to investigate zeta potential and particle size distribution of nanoparticle-surfactant formulations. Also scanning electron microscopy was used to examine the physicochemical aspects of the suspension.We found that the salt drastically reduced nanofluid stability (because of the screening effect on the repulsive forces between the nanoparticles), while addition of anionic surfactant improved stability. Cationic surfactants again deteriorated stability. Mechanisms for the different behaviour of the different formulations were identified and are discussed here.We thus conclude that for achieving maximum nanofluid stability, anionic surfactant should be added.

Time‐lapse full waveform inversion of vertical seismic profile data: Workflow and application to the CO2CRC Otway project

AbstractVertical seismic profile (VSP) is one of the technologies for monitoring hydrocarbon production and CO2 geosequestration. However, quantitative interpretation of time‐lapse VSP is challenging due to its irregular distribution of source‐receiver offsets. One way to overcome this challenge is to use full waveform inversion (FWI), which does not require regular offsets. We present a workflow of elastic FWI applied to offset vertical seismic profile data for the purpose of identification and estimation of time‐lapse changes introduced by injection of 15,000 t of CO2‐rich gas mixture at 1.5 km depth. Application of this workflow to both synthetic and field data shows that elastic FWI is able to detect and quantify the time‐lapse anomaly in P wave velocity with the magnitude of 100–150 m/s.

Dynamics of snap-off and pore-filling events during two-phase fluid flow in permeable media

Understanding the pore-scale dynamics of two-phase fluid flow in permeable media is important in many processes such as water infiltration in soils, oil recovery, and geo-sequestration of CO2. The two most important processes that compete during the displacement of a non-wetting fluid by a wetting fluid are pore-filling or piston-like displacement and snap-off; this latter process can lead to trapping of the non-wetting phase. We present a three-dimensional dynamic visualization study using fast synchrotron X-ray micro-tomography to provide new insights into these processes by conducting a time-resolved pore-by-pore analysis of the local curvature and capillary pressure. We show that the time-scales of interface movement and brine layer swelling leading to snap-off are several minutes, orders of magnitude slower than observed for Haines jumps in drainage. The local capillary pressure increases rapidly after snap-off as the trapped phase finds a position that is a new local energy minimum. However, the pressure change is less dramatic than that observed during drainage. We also show that the brine-oil interface jumps from pore-to-pore during imbibition at an approximately constant local capillary pressure, with an event size of the order of an average pore size, again much smaller than the large bursts seen during drainage.

Experimental assessment of pore fluid distribution and geomechanical changes in saline sandstone reservoirs during and after CO2 injection

Responsible CO2 geosequestration requires a comprehensive assessment of the geomechanical integrity of saline reservoir formations during and after CO2 injection. We assessed the geomechanical effects of CO2 injection and post-injection aquifer recharge on weakly cemented, synthetic-sandstone (38% porosity) sample in the laboratory under dry and brine-saturated conditions, before and after subjecting the sample to variable pore pressure brine-CO2 flow-through tests (∼170h). We measured ultrasonic P- and S-wave velocities (Vp, Vs) and attenuations, electrical resistivity and volumetric strain (εv). Vs was found to be an excellent indicator of mechanical deformation during CO2 injection; Vp gives mechanical and pore fluid distribution information, allowing quantification of the individual contribution of both phenomena when combined with resistivity. Abrupt strain recovery during imbibition suggests that aquifer recharge after ceasing CO2 injection might affect the geomechanical stability of the reservoir. Static and dynamic parameters indicate the sample experienced minor geomechanical changes during CO2 exposure, with an increase of Δεv <3% and a drop in ΔVs ∼1%. In contrast, due to brine-induced hydro-mechanical alteration, Δεv increased by ∼10% and ΔVs by ∼6%. This study provides a multiparameter, thermo-hydro-mechanical-chemical database needed to validate monitoring tools and simulators, for prediction of the geomechanical behaviour of CO2 storage reservoirs.