CO2 Storage Operations Research Articles

High-resolution imaging and characterization of a CO2 layer at the Sleipner CO2 storage operation, North Sea using time-lapse seismics

L arge-scale underground storage of industrially produced carbon dioxide is the most effective way of keeping cumulative man-made emissions of greenhouse gases within safe limits (IPCC, 2005). The CO2 injection operation at Sleipner, in the central North Sea between the UK and Norway, commenced in 1996 and is the world’s longest-running industrial-scale storage project. It is also the first example of underground CO2 storage arising as a direct response to environmental legislation (Baklid et al., 1996). CO2 separated from natural gas produced at the Sleipner field is being injected into the Utsira Sand, a regional saline aquifer of late Cenozoic age, in excess of 200 m thick in the Sleipner area (Figure 1a). The aquifer comprises mostly clean unconsolidated sand of high porosity (> 0.3) and high permeability (> 1 Darcy). A number of thin intra-reservoir mudstones, typically 1-2 m thick, are evident from geophysical logs acquired in wells around Sleipner (Figure 1b). The CO2 is injected in a dense phase via a deviated well at a depth of 1012 m below sea level, approximately 200 m beneath the top of the reservoir. Injection commenced in 1996 at a roughly constant rate, with around 16 million tonnes of CO2 stored by 2015. A comprehensive deepfocused monitoring programme has been deployed of which time-lapse seismic has proven to be the key tool (Arts et al., 2008). A baseline 3D survey was acquired in 1994, with repeat surveys in 1999, 2001, 2004, 2006, 2008, 2010 and 2012. The plume is imaged on the seismic data as a tiered structure some 200 m high comprising a number of bright sub-horizontal reflections (Figure 2a). These are interpreted as reflections from thin layers of CO2 trapped beneath the intra-reservoir mudstones which are partially but not wholly sealing. The reflective layering had formed by 1999 with each individual reflection traceable on all of the subsequent surveys. As a general rule the middle and upper reflections in the plume have increased in amplitude and lateral extent on successive time-lapse surveys, whereas the lower layers have ceased growing, in some cases shrinking and dimming. A key objective of the monitoring at Sleipner is to demonstrate that geological storage of CO2 is a safe and viable technology. One aspect of this is to quantitatively verify or constrain predictive flow simulations of plume development. However, because the injection well is near-horizontal, no wellbore penetrates either the CO2 plume or the exact stratigraphy that the plume now occupies, and quantitative analysis is challenging.

An Open-Source Toolchain for Simulation and Optimization of Aquifer-Wide CO2 Storage

Planning and execution of large-scale, aquifer-wide CO2 storage operations will require extensive use of computer modelling and simulations. The required computational tools will vary depending on the physical characteristics of the targeted aquifer, the stage of the project, and the questions asked, which may not always be anticipated in advance. In this paper, we argue that a one-size-fits-all simulation tool for the modelling CO2 storage does not exist. Instead, we propose an integrated toolchain of computational methods that can be used in a flexible way to set up adaptive workflows. Although a complete toolchain will require computational methods at all levels of complexity, we further argue that lightweight methods play a particularly important role in addressing many of the relevant questions. We have implemented a number of such simplified methods in MRST-co2lab, a separate module to the open-source MATLAB Reservoir Simulation Toolbox (MRST). In particular, MRST-co2lab contains percolation-type methods that within seconds can identify structural traps and their catchment areas and compute spill paths and rough estimates of trapping capacity. The software also offers two-phase simulators based on vertical-equilibrium assumptions that can forecast structural, residual, and solubility trapping in a thousand-year perspective and are orders of magnitude faster than traditional 3D simulators. Herein, we apply these methods on realistic, large-scale datasets to demonstrate their capabilities and show how they can be used in combination to address optimal use of open aquifers for large-scale storage.

Methodology to optimize the sizing of a corrective measure in case of leakage from a CO2 geological storage unit

To guarantee the safety of CO2 storage operations, to meet regulatory requirements and thus to be accepted by the public, the operator of a CO2 storage site has to demonstrate that the risks are adequately managed, which includes the treatment of potential irregularities. This paper proposes a methodology to choose a corrective measure and to optimize its sizing in case of leakage from a CO2 geological storage through a semi-pervious caprock, a fault, a fractured zone or any other leakage pathway on which it is difficult to directly act. The corrective measures considered in our work are limited to fluid and pressure management practices implemented for controlling the plume migration and eventually for extracting the leaking fluid. The methodology is based on the use of the Multi-Attribute Utility Theory (MAUT) which enables multi-criteria analysis over a continuous set of alternatives. The implementation on a case study illustrates the methodology applicability. The influence of the main assumptions and uncertainties are addressed through a sensitivity analysis.

Upscaling of CO2 injection into brine with capillary heterogeneity effects

The large-scale simulation of CO2 storage operations can be expensive computationally, particularly when the effects of fine-scale capillary pressure heterogeneity are included. The application of upscaling techniques could lead to substantial reductions in computational cost. This work targets the development of an upscaling procedure that is applicable for the CO2 injection stage, which corresponds to a drainage process. Specifically, we develop and apply a new upscaling technique for two-phase flow in heterogeneous formations with capillary heterogeneity effects. The procedure entails first upscaling capillary pressure in the capillary limit, and then computing coarse-scale relative permeability functions using a global dynamic upscaling procedure. An iterative method is applied to enhance the accuracy of the upscaled capillary pressure functions. The new dynamic upscaling approach is applied to a synthetic heterogeneous two-dimensional aquifer model that involves injection of CO2 into brine. Fine-scale simulation results are compared with coarse-scale results generated using both the dynamic upscaling approach and a simpler method that entails the use of upscaled capillary pressure in conjunction with rock relative permeability curves. It is shown that the dynamic upscaling procedure provides results that are close to those from the fine-scale simulation and are consistently more accurate than results from the simpler method. The upscaling procedure is tested over a range of injection rates spanning three orders of magnitude. We show that, although the upscaled functions are in general rate dependent, accurate coarse-scale results can be obtained using upscaled relative permeability functions computed at only two different flow rates. We also observe that the model constructed using our method retains reasonable accuracy even when the flow problem differs from that used to compute the upscaled functions.

The chemical dissolution and physical migration of minerals induced during CO2 laboratory experiments: their relevance for reservoir quality

The characterization of the quality and storage capacity of geological underground reservoirs is one of the most important and challenging tasks for the realization of carbon capture and storage (CCS) projects. One approach for such an evaluation is the upscaling of data sets achieved by laboratory CO2 batch experiments to field scale. (Sub)-microscopic, petrophysical, tomographic, and chemical analytical methods were applied to reservoir sandstone samples from the Altmark gas field before and after static autoclave batch experiments at reservoir-specific conditions to study the relevance of injected CO2 on reservoir quality. These investigations confirmed that the chemical dissolution of pore-filling mineral phases (carbonate, anhydrite), associated with an increased exposure of clay mineral surfaces and the physical detachment and mobilization of such clay fines (illite, chlorite) are most appropriate to modify the quality of storage sites. Thereby the complex interplay of both processes will affect the porosity and permeability in opposite ways—mineral dissolution will enhance the rock porosity (and permeability), but fine migration can deteriorate the permeability. These reactions are realized down to ~µm scale and will affect the fluid–rock reactivity of the reservoirs, their injectivity and recovery rates during CO2 storage operations.

Assessment of the effective CO2 storage capacity in the Beibuwan Basin, offshore of southwestern P. R. China

The Beibuwan Basin is a petroliferous sedimentary basin in Beibu Gulf in the northwestern South China Sea. This basin is surrounded by Guangxi, Hainan and Guangdong Provinces. Previous studies show that the onshore CO2 storage potential in Southeastern China is limited; thus the CO2 storage potential of offshore basins, including Beibuwan Basin, is crucial for CO2 capture and storage implementation in these areas. This study evaluates the potential for CO2 geological storage in the Beibuwan Basin through a desktop evaluation of existing data, to provide background data for planning regional carbon emission reductions. Deep saline aquifers and hydrocarbon reservoirs within the basin were evaluated for their suitability to store CO2 based on geological, geographical and environmental criteria, and the effective storage capacity was estimated. The estimates show that the Beibuwan Basin has suitable geological conditions with three super reservoirs of high porosity (20–30%) and permeability (200–300mD) and accompanying three widely distributed efficient sealing layers. The effective capacity for CO2 storage is 485.6×108t CO2 in deep saline aquifers of Beibuwan Basin; this capacity could potentially support CO2 sequestration for large power plants onshore in the Beibu Gulf area. The storage capacity of the oil and gas fields is limited, with average values of 42.3×106t CO2 and 62.3×106t CO2, respectively. The most prospective area for CO2 storage in Beibuwan Basin is within the Weixinan Sag which contains the Weixinan oilfield groups and plenty of potential structural traps, depending on the availability of porous units, including those that are non-oil bearing. The effective CO2 storage capacity of the Weixinan Sag is 47.2×108t CO2. Existing geological and geophysical data and facilities, including wells, pipelines and platforms for hydrocarbon production might help reduce costs for offshore CO2 transportation and storage operations. The mode of the oil and gas terminal treatment plant on Weizhou Island provides a centralised management model for CO2 storage. If this mode can be utilised, an offshore CO2 transport and storage cluster can also be created in the Weixinan Sag greatly reducing the cost of offshore storage. Evaluation of the feasibility of using these oil production facilities for CO2 storage and of the risk along abandoned wells and faults is urgent.

Utilizing spectral decomposition to determine the distribution of injected CO2 at the Snøhvit Field

ABSTRACTTime‐lapse 3D seismic reflection data, covering the CO2 storage operation at the Snøhvit gas field in the Barents Sea, show clear amplitude and time‐delay differences following injection. The nature and extent of these changes suggest that increased pore fluid pressure contributes to the observed seismic response, in addition to a saturation effect.Spectral decomposition using the smoothed pseudo‐Wigner–Ville distribution has been used to derive discrete‐frequency reflection amplitudes from around the base of the CO2 storage reservoir. These are utilized to determine the lateral variation in peak tuning frequency across the seismic anomaly as this provides a direct proxy for the thickness of the causative feature.Under the assumption that the lateral and vertical extents of the respective saturation and pressure changes following CO2 injection will be significantly different, discrete spectral amplitudes are used to distinguish between the two effects. A clear spatial separation is observed in the distribution of low‐ and high‐frequency tuning. This is used to discriminate between direct fluid substitution of CO2, as a thin layer, and pressure changes that are distributed across a greater thickness of the storage reservoir. The results reveal a striking correlation with findings derived from pressure and saturation discrimination algorithms based on amplitude versus offset analysis.

Review of CO2 storage efficiency in deep saline aquifers

At the time the IPCC Special Report on Carbon Capture and Storage was published in 2005, the concept of CO2 storage efficiency was not introduced yet and, consequently, no numerical values were published in the literature. CO2 storage efficiency is defined as the ratio of the volume of CO2 injected into an aquifer rock volume to the pore space in that volume and this concept has been first introduced in 2007 in regional-scale assessments of storage capacity in the United States and Europe. Since then many papers, reviewed in this article, have been published on the subject of efficiency of CO2 storage and associated values. CO2 storage efficiency depends on a multitude of factors that can be grouped into several categories: (1) Characteristics of the storage aquifer, such as in situ conditions of pressure, temperature and salinity, displacement characteristics of the CO2/brine system, lithology, porosity, permeability, heterogeneity and anisotropy, aquifer areal extent, thickness and boundaries; (2) Characteristics of the confining aquitards, mainly permeability and capillary entry pressure; (3) Characteristics of the CO2 storage operation, such as injection rate, duration of injection; number of injection wells, their orientation and their spacing, and injection strategy, including water production and/or injection; and (4) Regulatory constraints, such as maximum bottom-hole injection pressure, and definitions used to establish the volume of rock assigned for CO2 storage for a given project, such as scale of assessment (local or regional), relevant time (e.g., at cessation of injection or at plume immobilization), and relevant aquifer area (e.g., footprint of the CO2 plume itself, area where aquifer pressure is higher than a critical pressure, or area of tenure). Depending on the combination of factors listed above, values of storage efficiency as calculated to date and published in the literature vary in a wide range (from <1% to >10%, by a factor of 20 and even higher) and no single value or set of values can be universally used. Storage efficiency has both a spatial and a temporal dependency; being first pressure- and then space-limited; therefore it is critical in all assessments to specify the relevant aquifer area and time of reference. For closed aquifers, the cross-over time from pressure-limited to space-limited is achieved very quickly, and storage efficiency is based on the compressibility of the system. For open aquifers, a CO2 storage operation is most likely pressure-limited during its entire life. Storage resource estimates are theoretically time and space independent in the sense that the entire aquifer is considered, and the estimate represents what would be achieved if all the aquifer pore space would be accessible through a very large number of wells and over a very long period of time, much longer than a project life-time and the period of time needed to achieve climate stabilization. Volumetric estimates could be used for regional-scale evaluations of CO2 storage resources using values at the lower end of the spectrum of published values for storage efficiency. Dynamic estimates, based on numerical simulations that take into account operational and regulatory factors should be used for local-scale CO2 storage reserves estimates. Storage efficiency can be increased using storage engineering technology, such as water extraction and/or (re)injection, and the type and location of various injection and producing wells.

CO2 EOR and storage in Jilin oilfield China: Monitoring program and preliminary results

Jilin oilfield is conducting the first large scale demonstration project on CO2 EOR and storage in the northeast China. CO2 with high purity is produced from a nearby natural gas reservoir and injected into the tight oil reservoir of H-59 block. Up to early in 2012, more than 20×104 tons of CO2 has been injected into the reservoir through a miscible flooding scheme. In order to track the migration of CO2 in the reservoir and ensure a long-term storage safety, a monitoring program has been deployed in the field. The used monitoring techniques include wellbore integrity detecting, produced fluid sampling, CO2 gas tracer, electric spontaneous potential measurement, micro-seismic and cross-well seismic. An environmental monitoring program is also implemented for verifying CO2 leakage. Preliminary results indicate that it is effective to detect the movement of CO2 in the oil reservoir by jointly applying various monitoring techniques based on wellbores. After more than four years of operation since 2008, nearly 80% of injected CO2 has been stored in the reservoir with the rest of injected CO2 breakthrough in the production wells. CO2 storage safety needs more detailed and comprehensive monitoring data for further verification. The obtained preliminary monitoring experience can provide valuable guidance for the future enlarged Jilin project and other CO2 EOR and storage operations.

Surface controls on the characteristics of natural CO2 seeps: implications for engineered CO2 stores

AbstractCO2 injected into rock formations for deep geological storage must not leak to surface, since this would be economically and environmentally unfavourable, and could present a human health hazard. In Italy natural CO2 degassing to the surface via seeps is widespread, providing an insight into the various styles of subsurface ‘plumbing’ as well as surface expression of CO2 fluids. Here we investigate surface controls on the distribution of CO2 seep characteristics (type, flux and temperature) using a large geographical and historical data set. When the locations of documented seeps are compared to a synthetic statistically random data set, we find that the nature of the CO2 seeps is most strongly governed by the flow properties of the outcropping rocks, and local topography. Where low‐permeability rocks outcrop, numerous dry seeps occur and have a range of fluxes. Aqueous fluid flow will be limited in these low‐permeability rocks, and so relative permeability effects may enable preferential CO2 flow. CO2 vents typically occur along faults in rocks that are located above the water table or are low permeability. Diffuse seeps develop where CO2 (laterally supplied by these faults) emerges from the vadose zone and where CO2 degassing from groundwater follows a different flow path due to flow differences for water and CO2 gas. Bubbling water seeps (characterized by water bubbling with CO2) arise where CO2 supply enters the phreatic zone or an aquifer. CO2‐rich springs often emerge where valleys erode into CO2 aquifers, and these are typically high flux seeps. Seep type is known to influence human health risk at CO2 seeps in Italy, as well as the topography surrounding the seep which affects the rate of gas dispersion by wind. Identifying the physical controls on potential seep locations and seep type above engineered CO2 storage operations is therefore crucial to targeted site monitoring strategy and risk assessment. The surface geology and topography above a CO2 store must therefore be characterized in order to design the most effective monitoring strategy.

Monitoring of saturation changes and salt precipitation during CO2 injection using pulsed neutron-gamma logging at the Ketzin pilot site

During injection of CO2, monitoring of the subsurface saturation changes is required. For well logging in cased boreholes only a limited number of techniques such as radiometric pulsed neutron-gamma (PNG) logging are applicable. The conventional PNG saturation model mainly considers a displacement process. But during CO2 injection additional processes such as evaporation and salt precipitation are expected to occur as a result of the mutual solubility between brine and CO2. For this purpose an extended PNG saturation model for NaCl-brines is developed and applied to a time-lapse PNG monitoring data set from the Ketzin site. The results show that for the observation well further away from the injection well, the conventional displacement saturation model is valid, with average CO2 saturations below 60%. In contrast, the data from the injection well shows that both evaporation and salt precipitation have occurred. Here, the largest CO2 saturations with values up to 100% are determined locally. The results of the extended saturation model indicate that dry-out regions, where only CO2 and halite with saturations up to 1.4% exist, and maximum halite saturations up to 14.1% occur in the vicinity of the brine levels. The halite saturation distribution in the injection well seems to be controlled by changes in the injection regime associated with changing brine levels, lithological heterogeneities, and capillary effects. PNG monitoring in combination with the extended saturation model is suited to determine displacement and evaporation/precipitation processes for CO2 storage operations.

Quantitative risk assessment in the early stages of a CO2 geological storage project: implementation of a practical approach in an uncertain context

AbstractMethodologies for quantitative risk assessment regarding CO2 storage operations are currently scarce, mostly because of the lack of experience in this field and the relatively significant degree of uncertainty regarding the subsurface intrinsic properties and the processes occurring after the injection starts. This paper presents a practical approach designed to perform a quantitative risk assessment in an uncertain context. Our approach is illustrated by a realistic case study (Paris Basin, France), conceived to be representative of the level of information available in the early stages of a project. It follows the risk assessment principles from the international standards (ISO 31000:2009), which are adapted to account for the specificities and challenges of subsurface operations. After the establishment of the context of the specific case study, the main risks are identified and we analyze two different risk scenarios: risk of brine leakage from an abandoned well and risk of subsurface use conflict.These scenarios were selected to give a comprehensive overview of different types of analysis in terms of available data, modeling tools and uncertainty management methodologies. The main benefit of this paper is to propose an approach, based on existing risk assessment standards, best practices, and analysis tools, which allows an objective quantitative risk analysis taking into account the uncertainties, and therefore enabling fully informed decision‐making while evaluating risk acceptability.

Fracture corridors as seal-bypass systems in siliciclastic reservoir-cap rock successions: Field-based insights from the Jurassic Entrada Formation (SE Utah, USA)

Closely spaced, sub-parallel fracture networks contained within localized tabular zones that are fracture corridors may compromise top seal integrity and form pathways for vertical fluid flow between reservoirs at different stratigraphic levels. This geometry is exemplified by fracture corridors found in outcrops of the Jurassic Entrada Formation in Utah (USA). These fracture corridors exhibit discolored (bleached) zones, interpreted as evidence of ancient fracture-enhanced circulation of reducing fluids within an exhumed siliciclastic reservoir-cap rock succession. Extensive structural and stratigraphic mapping and logging provided fracture data for analysis with respect to their occurrence and relationships to larger faults and folds. Three types of fracture corridors, representing end-members of a continuum of possibly interrelated structures were identified: 1) fault damage zone including segment relays; 2) fault-tip process zone; and 3) fold-related crestal-zone fracture corridors. The three types exhibit intrinsic orientations and patterns, which in sum define a local- to regional network of inferred vertical and lateral, high-permeability conduits. The results from our analysis may provide improved basis for the evaluation of trap integrity and flow paths across the reservoir-cap rock interface, applicable to both CO2 storage operations and the hydrocarbon industry.

Significance for secure CO2 storage of earthquakes induced by fluid injection

The link between subsurface fluid injection and induced seismicity has gained recent significance with an increase in earthquakes associated with the disposal of oilfield waste fluids. There are obvious similarities between wastewater reinjection and proposed CO2 storage (CCS) operations. However, as well as the seismic hazard, induced seismicity during CCS operations poses additional risks, because an induced event located above the target reservoir could compromise the hydraulic integrity of the caprock. In this paper we re-examine case examples where earthquakes have been induced by wastewater injection into deep aquifers in the light of proposed future CCS operations. In particular we consider possible controls on event magnitudes, and look at the spatial distributions of events. We find that the majority of events are located below the target reservoirs. This is an encouraging observation from the perspective of caprock integrity, although it presents a challenge in terms of pre-injection characterization of deep-lying faults several kilometres below the target zone. We observe that 99% of events are found within 20 km of injection wells, suggesting a minimum radius for geomechanical characterization and monitoring. We conclude by making recommendations for modelling and monitoring strategies to be followed prior to and during commercial-scale deployment of CO2 storage projects.

CO2 storage safety and leakage monitoring in the CCS demonstration project of Jilin oilfield, China

AbstractJilin oilfield is conducting the first large‐scale demonstration project on CO2 storage and enhanced oil recovery (EOR) in the northeast of China. A comprehensive monitoring program has been designed and deployed in the target reservoir of block H‐59 using a wide range of techniques to monitor the injection and production systems, the CO2 migration fronts, and potential CO2 leakage pathways. Tube fault detection, corrosion inhibitors, anti‐CO2 corrosion cement, and production dynamic analysis have been adopted to guarantee the safety at the well site. CO2 movement in the reservoir is detected mainly by gas tracer, electric spontaneous potential measurement, and fluid sampling. Near‐surface environmental monitoring is also conducted around the injection site. Field experience has shown that the monitoring targets should be focused on the reservoir, near‐surface, and injection and production systems. Applying monitoring techniques to ensure the integrity of wellbores can not only prevent the leakage of CO2, but also avoid the blind expansion of monitoring program scopes. It is reliable and economical to take full advantage of techniques based on wellbores to monitor CO2 movement in oil reservoirs with dense well patterns. Up to April 2013, nearly 21.7 × 104 tons of CO2 has been injected without obvious leakage caused by integrity failure of wells or the geological structure of reservoir. More than 96% of injected CO2 has been safely stored with the rest of injected CO2 normally breakthrough in the production wells. The preliminary monitoring experience obtained can provide valuable guidance for the future enlarged Jilin project and other CO2 EOR and storage operations.

Managing CO2 Storage Resources in a Mature CCS Future

This paper summarises the potential for surface and subsurface interactions which might occur during CO2 storage operations. We discuss possible options for managing these interactions to provide timely storage capacity, illustrated with a regional case study from the Southern North Sea. The case study evaluates storage site options to provide storage capacity for CO2 supplied to the region until 2050.

Examining Epoxy-based Nanocomposites in Wellbore Seal Repair for Effective CO2 Sequestration

Thousands of abandoned wellbores may lie within the aerial extent of a CO2 storage operation. These wellbores represent a potential leakage pathway and a leaky wellbore needs to be re-completed or otherwise repaired to restore seal integrity and ensure containment of the stored CO2. Due to the high cost of recompleting a well, a sufficient economic incentive exists if a viable seal repair technology is available. In this paper, we examine the use of epoxy nanocomposites as potential seal repair materials that have excellent bond characteristics with both steel and cement when cured in the subsurface environment. Test results show Novolac epoxy nanocomposites incorporating nanosilica, nanoclay or nanoalumina to have acceptable flowability that enable injection in wellbore cracks and significantly higher bond strength compared with standard microfine cement.

CO2 Utilization and Storage in Shale Gas Reservoirs: Experimental Results and Economic Impacts

Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO2 emissions involves coupling CO2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO2) and associated economic consequences. Where enhanced condensation of CO2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO2. Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO2 intercalation. In contrast, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO2 gas systems, where CH4 concentrations prevail, indicate preferential CO2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO2-EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO2 exchange rates to obtain peak natural gas production.

Artificial Neural Network based surrogate modelling for multi- objective optimisation of geological CO2 storage operations

Abstract An Artificial Neural Network surrogate modelling approach was used to optimise CO2 storage into a highly heterogeneous semi- closed saline aquifer which exhibits considerable pressure increase due to injection. The methodology was implemented to minimise the overall field pressure and well bottom-hole pressures, and to maximise the amount of dissolved and trapped CO2 in the storage aquifer. Different realisations of permeability and porosity were stochastically generated to represent the uncertainty in the model. Artificial neural networks were used to reduce the computational time of the optimisation procedure by approximating the objective functions for CO2 storage as surrogates to the expensive solutions of flow by the simulator. A multi- objective evolutionary algorithm was run on these approximators to generate solutions of the multi-objective optimisation's Pareto front. These solutions were compared with the solutions obtained by the computationally expensive optimisation and they were found to give satisfactory results, illustrating that this methodology can be a viable, and low computational cost alternative for optimisation in CO2 storage design.

Well injectivity during CO2 storage operations in deep saline aquifers – Part 2: Numerical simulations of drying, salt deposit mechanisms and role of capillary forces

The injection of CO2 into geological reservoirs or deep saline aquifers is being studied to control global warming by limiting greenhouse gas emissions. CO2 is captured from exhaust gases in power plants or industrial units and stored in underground geological reservoirs. Return on experience with CO2 injection in the oil industry clearly shows that injectivity problems can be encountered due to several mechanisms including mineral dissolution/precipitation and physical alteration due to the complete desaturation of the near-wellbore zone. This study describes numerical modelling that is able to reproduce the experimental results of drying of brine-saturated sandstone cores by gas injection in the laboratory. The evolution of water and gas saturation profiles and the precipitation of salt inside the samples are followed with injection time. Numerical results agree well with experimental observations highlighting the key role played by capillary forces during the desiccation process (see the companion paper; Peysson et al., 2014). A tentative extrapolation of experimental results from laboratory scale to the near-well field scale is proposed. This approach is of major importance because it makes it possible to determine the optimal CO2 injection flow rate according to both the intrinsic petrophysical properties of the porous medium and initial brine salinities.