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CO2 geo-sequestration can significantly contribute to the reduction of greenhouse gas emissions. Out of all geological CO2 storage sites, mature oil fields are often considered primary targets for CO2 sequestration as one of Carbon Capture, Utilisation and Storage (CCUS) approaches where the operation cost can be offset by enhancing oil recovery and utilising the existing facilities. However, a geological formation with large volumetric capacity (pore volume) is not necessarily an appropriate candidate for CO2 storage and CO2 injectivity plays equally an important role for site selection to store CO2. Therefore, evaluation of CO2 dynamic storage capacity (injectivity) and ultimate CO2 enhanced oil recovery (EOR) are key elements for a successful CO2 storage – EOR project. CO2 EOR was considered as a suitable tertiary oil recovery approach after very short and inefficient primary and secondary oil recoveries in Yanchang oil field, the second largest tight oil field in China, located at Ordos Basin in north western China. This paper describes the acquisition of essential dynamic data from a reservoir in Yanchang oil field to evaluate its CO2 injectivity/dynamic storage capacity. For that, numerical reservoir simulation was utilised to model and history match the target reservoir. The history matched model was then used to numerically perform several testing scenarios resulting in the selection and design of the most appropriate test. A unique two-stage well testing approach was proposed to inject water and CO2 into one well and observe the pressure at two monitoring wells for a total testing period of about one year. It accurately estimates formation effective permeability in both the water flooded zone (test stage 1) and the CO2 flooded zone (test stage 2) at the injecting well. Also, it qualitatively estimates the water and CO2 fronts in the reservoir as well as CO2 injectivity using data at the injecting well. The radius of investigation (ROI) significantly increases by adding two monitoring wells to the existing injecting well. Using two monitoring wells also identifies heterogeneities and lateral anisotropy in the reservoir. The recently acquired field data, as part of this well testing program, indicate that the reservoir characteristics at the monitoring wells are significantly different from each other, suggesting the existence of considerable heterogeneity/anisotropy in the reservoir. The results generated by this well test are included in the reservoir model to reduce uncertainties for the future CO2-EOR field development plan. Finally, more informative decisions can be made on whether or not a field is suitable for a CO2-EOR project to unlock further oil resources from tight formations.

This commentary addresses “Numerical investigation of the potential contamination of a shallow aquifer in producing coalbed methane” by Xianbo Su, Fengde Zhou, and Stephen Tyson. We think the models used in the simulations described in the paper are unrealistic, even as a conceptual worst case scenario. Concerns regarding how the results of these simulations are interpreted and portrayed, and in particular how they are related to previous works are discussed in detail. We believe the original paper uses language which could be misleading, and possibly alarmist, and we suggest references cited in the original paper may have been misinterpreted.

Static and dynamic models often simplify coal measures as laterally continuous seams between interburden layers. However, coals are not always laterally continuous and are frequently heterogeneously distributed within interburden. Formation water often contains a high concentration of gas, and in many cases is likely at saturation. Groundwater extraction from coal seam gas (CSG) reservoirs, therefore, will produce free gas from both: i) gas desorption from the coal matrix, and ii) gas exsolution of dissolved gas in formation water. This generated gas could be produced from the well or it may migrate up-dip in-situ due to buoyancy effects. Accounting for solubility effects (i.e. the dissolved load degassing component of the free gas phase) while modelling gas production from coal requires additional field data gathering/analysis effort and brings extra computational cost. In this work, for both layered and heterogeneous coal-interburden systems, we use conceptual numerical simulations to demonstrate that gas dissolution/exsolution considerably affects the prediction of gas desorption rate, production rate, and gas migration flux. Two coal-interburden systems are considered in this paper. Both contain 20% coal, one with laminated coal layers and the other with heterogeneously distributed coal bodies within a shale interburden. Static geological models were built within a 1km×1km×20m cube. A vertical production well at a constant pressure of 100kPa was placed in the middle of the models and perforated along its entire thickness. Implementing a dual-porosity dual-permeability approach, multiphase flow was modelled once with, and then without, accounting for the dissolution/exsolution of the aqueous phase. Results show that allowing the aqueous phase to produce gas leads to an increase in the gas production rate from the heterogeneous case; however, it decreases the gas production from the layered coal model in early time steps. Results suggest that a detailed understanding of the dissolved gas load in CSG reservoirs will assist in improving gas production predictions at the well head.

The level of confidence in sub-surface containment related to potential industrial-scale injection of carbon dioxide (CO 2 ) is investigated in advance of applications for CO 2 exploration tenements. Evidence for seal retention pressures is evaluated based on hydrocarbon accumulations and hydrostatic gradients. Fracture propagation and fault reactivation pressures are also scoped. Evidence for vertical migration through a proposed seal is investigated through oil shows analysis. Analyses are synthesized and compared to required pressure retention performance, indicated by dynamic modeling, to give an overall view of pre-licensing, pre-drill containment confidence. The resultant uncertainty analysis is used to guide an exploration strategy.

At the Ketzin test site significant differences of wellhead pressures and temperature anomalies have been recorded at two observation wells after the arrival of CO2. Analysis of the measured well temperature and pressure data, and the deduced fluid density data shows that two-phase fluid conditions are prevailing in the upper 400 m of the wells. Implications on reservoir monitoring and well logging are discussed.

In 2006, the CO2ReMoVe project funded by the European Commission was launched with the objectives of developing new and common methodologies and technologies to improve site based R&D for the monitoring, measurement and verification of the injection and storage of CO2 at multiple sites. The In Salah Gas Krechba Field Joint Industry Project has been in operation since 2004 when gas from several fields was put on production. To comply with export regulations, the high content of carbon dioxide (CO2), 1–10% in the produced gas is removed and re-injected down dip from the producing gas horizon, through three horizontal injection wells at approximately 1800 m below surface. Within the framework of CO2ReMoVe, this paper discusses the site characterization and the short term system performance for the In Salah Krechba field.Prior to the injection, the reservoir unit and the seals were characterized. The resulting geological (static) model is consistent with the information obtained from the drilling activities in 2004 and 2005 and from the reprocessed 3D seismic done by Compagnie Générale de Géophysique (CGG) in 2006. A fracture study carried out on information obtained from resistivity and acoustic images available on the Krechba field had shown the existence of an open fracture network oriented along the NE-SW direction parallel to the maximum stress direction.Typically, monitoring data serves as a calibration yardstick for the static model. It was therefore valuable information to detect the CO2 breakthrough at KB-5, a suspended well located 1.7 km away from the KB-502 injector well. Tracer analysis confirmed the CO2 detected at KB-5 came from KB-502. A multi-phase, multi-component compositional simulator specially designed for CO2 sequestration (ECLIPSE11Mark of Schlumberger. 300 with the CO2SOL option) was used to simulate and predict the properties of the injected carbon dioxide as well as that of the gas in place (mainly methane) and of the saline aquifer. History matching was used to calibrate the dynamic model by iteratively modifying parameters until a satisfactory match between model results and field measurements was obtained. The resulting dynamic model is used for short term predictions of the behaviour of injected CO2. The history matching parameters are the fracture porosity, permeability and matrix permeability (difficult to measure permeability in a fractured medium). In each iteration, the simulated bottomhole pressures, gas (CO2) injection rates were compared against field data as well as the CO2 breakthrough time at KB-5. Iterations were repeated until a good match was obtained.Predictive simulation results indicate that CO2 would reach the northern part of the gas field in 2010 and would spread out over an area including production wells in 2015, both in the northern (KB-502, KB-503) and the eastern part (KB-501) of the gas field.Although a good match has been obtained in the history matching process, some observed discrepancies could still not be explained only by fluid dynamics. Possibly, the application of coupled fluid flow and geomechanical simulations would aid in explaining the remaining discrepancies.

This paper reports the well design, drilling and completion operation as well as the coring technique applied in the CO2SINK project. Three boreholes, one injection well and two observation wells have been drilled to a total depth of about 800 m. 200 m of recovered 6” core material has been real-time analysed in a research field lab. The wells have been completed as “smart” wells, containing a variety of permanently installed down-hole sensors for the continuous monitoring of the CO2 in the reservoir. All wells were cased with stainless final casings equipped with pre-perforated sand filters in the reservoir zone and wired on the outside with fiber-optical and multi-conductor copper cables. The reservoir casing section is externally coated with a fiber-glass-resin wrap for electrical insulation.

Since April 2004, preparatory work prior to CO2 injection has been conducted in the CO2SINK Project, the European Union's first research and development activity on the in-situ testing of geological storage of CO2 near the town of Ketzin, Germany. Carbon dioxide will be injected into a saline aquifer of the Triassic Stuttgart Formation in an anticlinal structure of the northeast German Basin. The drilling of one injection and two observation wells will commence at the end of 2006. The predrilling phase focuses on the baseline geological parameters of the anticline. The Stuttgart Formation is lithologically heterogeneous; it consists of sandy channel-(string)-facies rocks, with good reservoir properties alternating with muddy flood-plain-facies rocks of poor reservoir quality. Playa-type rocks form the immediate cap rock above the CO2SINK reservoir. A geostatistical approach has been applied to describe the reservoir architecture between and beyond well control. This model forms the basis for the generation of reservoir-dynamic models of CO2 injection that assist in the planning of injection operations and in the understanding of CO2 plume evolution. A verification of the geometry of the reservoir and the structural situation of its overburden is expected from a three-dimensional baseline seismic survey that was conducted in the autumn of 2005. Laboratory experiments under simulated in-situ conditions were performed to evaluate the geophysical signature of rocks saturated with CO2. The chemical composition of the groundwater and the CO2 flux in the soil were analyzed across the Ketzin anticline, providing the baseline for a monitoring program during and after injection of CO2, targeted at the detection of potential CO2 leakage from the storage reservoir.

Effective geological storage of CO2 can be accomplished through a number of trapping mechanisms. Physical trapping is achieved through either CO2 being trapped under a structural closure or CO2 made immobile in the pore space, as residual saturation, by capillary action. Geochemical trapping, which might be regarded as a more secure mode of storage, is achieved through dissolution of CO2 in formation water and precipitation of carbonates. The dissolution rate depends on surface contact and is generally enhanced by greater CO2 plume movement. During site selection, a potential injection well location is commonly evaluated with respect to the proximity to potential leakage features. This paper investigates requirements for separation distance between CO2 injection location and potential leakage features in highly permeable steeply dipping brine reservoir settings. Reservoir models are simulated with a compositional code and sensitivity analyses performed with variations in reservoir permeability, hysteresis effects, and formation dip. Trapping mechanisms, over a timescale of several centuries, are illustrated as key indicators for containment and storage performance. Study results suggest that the amount of CO2 trapped by dissolution and residual saturation is enhanced by a dynamically flowing plume. The simulation results demonstrate that the separation distance requirement typically envisaged in a worst-case reservoir geometry setting is commonly overly conservative, representing opportunity for further optimisation. Numerical simulation is useful in addressing the complex reality of flow dynamics such as hysteresis in footprint prediction. Understanding CO2 plume migration scenarios relative to potential leakage risks, under various key reservoir key properties, is essential in storage containment and capacity assessments for storage site selection and development.

This reservoir geomechanical study assesses the impact on top and fault seals integrity of fluid pressure changes associated with carbon dioxide (CO 2 ) storage in a saline formation. The case studied is the CO2SINK experiment at in Ketzin, Germany, where up to 60 ktons of CO 2 are being injected. Injection commenced in June 2008. A 3-dimensional (3D) geomechanical model of the site is built through integrated analyses of geologic, seismic, logging, drilling, and laboratory test data. First, the grid is expanded from a reservoir model up to surface, down to basement and laterally by about 3 times the pressure perturbation dimensions, while honouring all available structural, stratigraphic and lithological data. The grid cells are populated with density, poroelastic and strength properties upscaled from a 1-dimensional (1D) mechanical model built and validated along the Ktzi 201/2007 CO 2 injector well. Cells cut by faults are considered an equivalent medium representative of a jointed rock mass. The 3D geomechanical model is then dynamically linked to the reservoir model. Static equilibrium prior to injection is achieved by applying initial fluid pressure and gravity loads, as well as stress boundary conditions chosen so as to match in situ stress measurements. Stress path and rock deformation associated with CO 2 injection are then simulated. Pressure change data is passed from the flow simulator to the geomechanical simulator at selected time steps. Calculated stress path and strains are then used to investigate the possible occurrence and location of caprock failure and fault reactivation. Other results, such as ground surface elevation changes and sources of uncertainties are also highlighted. No failure is observed in the caprock and faults remain stable during CO 2 injection operations. Limited vertical displacement (maximum 5 mm) is predicted at surface.

Many stakeholders are concerned about the effects of Coal Seam Gas (CSG) developments on aquifers. Well integrity issues are often mentioned as potential leakage pathways which could lead to aquifer contamination or depletion. This study involved the creation of simple models to represent the behaviour around a producing CSG well with a well integrity failure. A range of realistic scenarios were chosen, representing hypothetical well integrity failures at different stages of CSG production. Dynamic numerical models were built that represent each scenario, and simulations were run to forecast the flux of fluids around the wellbore. These models were parameterized based on data from literature related to well integrity studies, and should represent reasonable worst-case scenarios. The results of simulations using these models are then used to explain key concepts relating to well integrity in CSG wells in a manner which can be understood by interested parties from non-technical backgrounds. The simulation results based on these simple models indicate that well integrity issues in producing (or previously produced) CSG wells are unlikely to have any significant impact on overlying aquifers.

Stress-dependent permeability in coal seam gas (CSG) reservoirs can challenge the development of coal fields with lower initial permeabilities. Thus, advanced well stimulation techniques become essential. This work evaluates the performance of novel graded proppant injection (GPI) technique for CSG reservoir stimulation using reservoir simulation models. A simplified model for steady-state incompressible fluid flow during the early dewatering stage of production is validated by the analytical model results. A general model is then developed for GPI process during unsteady-state compressible two-phase flow in coal, accounting for gas desorption, matrix shrinkage, heterogeneous permeability distribution, and cross-flow. Fractured porous medium is modelled by a dual-porosity radial model. Stress-dependent permeability and matrix shrinkage effects are modelled using the Palmer-Mansoori equation. Under the incompressible fluid flow condition, the productivity index after well stimulation using GPI technique increases by 1.3~2.3 times. Moreover, simulation of compressible gas-water flow coupled with gas desorption from matrix yields 4~13% increment on recovery factor (RF) during production for 30 years. Stimulation accounting for matrix shrinkage enhances RF by 9~13%. For heterogeneous permeability distribution, more permeable layers exhibit deeper penetration of particles. The enhanced permeability owing to GPI yields higher production of both gas and water. Cross-flow between the coal layers influence the effectiveness of the depressurisation process and hence gas desorption post-stimulation. It allows dewatering of deeper layers and additional desorption of gas.