Depleted Gas Fields Research Articles

Mitigating induced seismicity around depleted gas fields based on geomechanical modeling

Mitigation of induced seismicity associated with large-scale energy production from subsurface resources requires models beyond the current state of the art. In countries with long histories of conventional gas production, such as the Netherlands, issues are mainly associated with depletion-induced seismicity caused by fault reactivation due to differential compaction of reservoir compartments that are juxtaposed at faults. Geomechanical modeling approaches can be extended and integrated to better assess the occurrence of depletion-induced seismicity and provide a basis to modify operations with the aim of mitigating seismicity. Static models of fault stability and reactivation can be used to analyze the location and likelihood of fault reactivation during injection or depletion operations. Dynamic models of fault rupture and seismic wave propagation can be used to analyze the characteristics of induced seismicity from seismic source to expressions (motions) at surface or potential sensor locations. Ensemble-based optimization workflows can be used to maximize production under constraints imposed by thresholds for induced seismicity. The combination of these modeling approaches can be used to determine fault sections that are most prone to induce seismicity, analyze the fault rupture process and associated characteristics of induced seismicity, and optimize well production strategies for minimizing induced seismicity. Integrated geomechanical modeling of depletion-induced seismicity and production optimization workflows can lead to gas production strategies that maximize total gas production while minimizing seismic risk.

Time-dependent modeling of subsidence due to drainage in bounding shales: Application to a depleted gas field in Louisiana

Hydrocarbon production is an important process contributing to the subsidence in Louisiana. Releveling data from National Geodetic Survey show that subsidence along several major oil and gas fields accelerated after production when reservoirs were nearly depleted. The Valentine gas field in coastal Louisiana is chosen to analyze the subsidence during and after production based on three-dimensional finite element modeling. An elastic-viscoplastic constitutive model is adopted to interpret the accelerated postdepletion subsidence by overcoming the limitation of traditional theories within the framework of poroelatsicity and poroplasticity. The elastic-viscoplastic model integrates a failure envelope, an elliptical cap yield function, and Perzyna's theory of overstress viscoplasticity. The elastic-viscoplastic model is applied to both the simplified disc-shaped reservoir and the bounding shales. The material properties of the elastic-viscoplastic model are calibrated based on a computational technique along with available laboratory and field data from the literature. The numerical modeling results can approximately reproduce both the observed subsidence during production and the delayed subsidence after production using the calibrated material properties. The time-dependent subsidence is predominantly attributed to the delayed compaction that arises from the slow pore pressure diffusion in the bounding shales after the reservoir is depleted. The calibrated finite element model is capable of predicting the time-dependent compaction and subsidence, along with the three-dimensional temporal and spatial distribution of pore pressure, void ratio, vertical strain, and vertical displacement in the bounding shales. The pore pressure diffusion and the time-dependent subsidence are influenced by the permeability of both the reservoir sand and bounding shale. Even though permeability generally increases with damage, and decreases with increased effective stress and reduced porosity, typical constant values of permeability are used for simplicity. The local maximum subsidence is predicted to be 28 cm during 30 years (1982–2012) after the Valentine field is depleted.

TECHNOLOGY OF INCREASE OF WELL CAPACITY BY METHOD OF IMPROVING THE FORMATION EXPOSING CHARACTER

Background There is a well-developed system of underground gas storage (UGS) in Russia nowadays. It is a key instrument for smoothing out the peak loads and regulating the seasonal fluctuations in gas demand, for optimizing the operational modes of the main pipelines and investment costs of their construction, and for maintaining the flexibility and reliability of gas supplies to the consumers. At present, Gazprom operates 22 underground gas storage facilities at 26 gas storages in Russia: 17 - in depleted gas fields, 8 - in aquifers and 1 - in а salt cavern. The daily productivity highly depends on the quantity and quality of production wells. The quality of well is determined by its perfection in area of a filtration zone. The influence of these factors on production rate of wells in relation to the underground gas storages of Russia is considered in the article. Aims and Objectives The production rate of well can be increased several times by eliminating part of the perforated production string, as barriers to filtration processes in the bottomhole zone of the formation and increasing the filtration area due to the expansion of the bottomhole zone in the productive interval of the reservoir. In the article the technology and the tool allowing to improve a well during repair works are considered. Results Currently, the technology has been successfully implemented at 88 wells in the UGS facilities in Russia, resulting in a reduction in coefficients of filtration resistance, in increase in well productivity with a decrease in depression after the expansion of the wellbore in the interval of the productive reservoir.

Three layers of energy law for examining CO2 transport for carbon-capture and storage

This research is a legal analysis concerning four scenarios for cross-border carbon dioxide (CO2) transport that could increase the deployment of carbon-capture and storage (CCS) deployment in Europe. The legal analysis categorizes the law into three levels-international, national and local-and considers the four scenarios in light of these three levels of energy law. Upon reviewing the four scenarios, it is clear that the Rotterdam Nucleus (referred to as the 'Pilot Case') is the leading scenario and as a result it is explored in more detail. The potential Pilot Case is based on the development of Rotterdam (in the Netherlands) as a southern North Sea hub. Under this Rotterdam Nucleus scenario, captured CO2 will be transported through the Port of Rotterdam to depleted gas fields offshore the Netherlands. CO2 will also be transported through further links using CCS infrastructure to facilitate the processing of undeveloped gas fields offshore UK. The Pilot case contemplates further expansion opportunities, increasing the capture clusters through additional pipelines, expanding to further gas fields and using the port of Rotterdam for CO2 shipping-hence the analysis of the other scenarios may be invaluable in the future development of CO2 networks in the EU. Finally, and an original contribution of this article is that it employs the three lawyers of energy law theoretical framework to an energy problem that was examined by an interdisciplinary research team. Furthermore, this research was developed further through two key industry stakeholder meetings with CCS experts in the EU. © The Author(s) 2018. Published by Oxford University Press on behalf of the AIPN. All rights reserved.

Assessment of CO2 - EOR and Storage Capacity in South Sumatera and West Java Basins

A study of carbon dioxide-enhanced oil recovery (CO2-EOR) and storage capacity in South Sumatera and West Java Basins, Indonesia has been conducted in conjunctions with the project plans of Indonesia National Electric Company to build carbon capture and storage ready coal power plants in Bojonegara of West Java and Muara Enim of South Sumatera. The Bojonegara power plant comprises 2×1000 MWe Ultra Super Critical Units, while Muara Enim consists of 2×300 MWe subcritical units. Those two power plants will produce approximately 11 and 4 million tons of CO2 per year. The geology of South Sumatera and West Java Basins are proven to have kept oil and gas in place safely for long time periods and there are many oil and gas companies production still active in those basins. Those basins are confirmed to be used as storage of CO2, where capacity, injectivity, and confinement will be suitable to keep CO2 in place for a period of time. CO2 production from those power plants in South Sumatera and West Java may be offered to the nearby oil companies and transported to oil fields for CO2-EOR flooding to get additional revenue. A preliminary CO2-EOR screening has been done for the oil fields surrounding the power plants. There are two types of mechanisms for CO2-EOR, which depend on the nature of the oilfield: immiscible EOR and miscible EOR. Immiscible EOR occurs where the injected CO2 does not mix with the oil but instead displaces the oil from the area where the CO2 is injected and increases the pressure of the oil at the production wells so that it can be pumped out. Miscible EOR occurs where the supercritical CO2 mixes miscibility with the residual oil to make it less viscous and facilitating its flow to the production wells. A total of 127 oil fields in South Sumatera has been analyzed to select which of those fields fulfill CO2-EOR injection criteria. EOR reservoir screenings were performed on those oil fields on which detailed information was available using the screening criteria proposed by Taber et al. The criteria include a set of parameters such as API gravity, oil viscosity, current pressure, temperature, oil saturation, remaining oil, formation depth, thickness, porosity, permeability, and rock type which help to determine whether or not a reservoir is suitable for CO2-EOR injection. 96 fields are classified as miscible displacement while the remaining 31 fields are categorized as immiscible. The result shows that the potency of additional recovery from those fields is around 661 million stock tank barrels with CO2 requirement of approximately 243 million tonnes. In addition to EOR, pure CCS to inject the CO2 emission into depleted gas fields in West Java and South Sumatera regions is also considered. The maximum storage capacity of West Java gas fields is approximately 395 million tonnes, while the storage capacity of South Sumatera is around 537 million tonnes. The potential for storing CO2 in the saline aquifer was also calculated theoretically. The depleted gas fields and aquifers are considered enough to store the CO2 emission from the power plants as long as 25 years.

Using Pressure Recovery at a Depleted Gas Field to Understand Saline Aquifer Connectivity

A key uncertainty facing Carbon dioxide Capture and Storage (CCS) in saline aquifers is long term injectivity, which is primarily a function of the connected aquifer pore-volume within which formation brine can be displaced as the CO2 is injected. Protracted injection testing to interrogate and prove the far-field connected pore-volume would increase the lead-in times for commissioning of storage sites and would significantly increase appraisal costs. Here we use natural gas production and subsequent reservoir recharge legacy data from the Esmond gas field in the UK sector of the southern North Sea to gain an understanding of the dynamic behaviour of the Bunter Sandstone, a major saline aquifer. Results suggest that Esmond has a connected pore volume of 1.83x1010 m3, suitable for injecting CO2 at a rate of up to 2 million tonnes per year for at least 55 years. 3D seismic data suggest that Esmond reservoir properties are likely to be replicated across the wider Bunter Sandstone aquifer, notably around the Endurance structure which was, until recently, proposed for a full-chain CCS project.

Mesoscale Assessment of CO2 Storage Potential and Geological Suitability for Target Area Selection in the Sichuan Basin

In China, south of the Yangtze River, there are a large number of carbon sources, while the Sichuan Basin is the largest sedimentary basin; it makes sense to select the targets for CO2 geological storage (CGUS) early demonstration. For CO2 enhanced oil and gas, coal bed methane recovery (CO2-EOR, EGR, and ECBM), or storage in these depleted fields, the existing oil, gas fields, or coal seams could be the target areas in the mesoscale. This paper proposed a methodology of GIS superimposed multisource information assessment of geological suitability for CO2 enhanced water recovery (CO2-EWR) or only storage in deep saline aquifers. The potential per unit area of deep saline aquifers CO2 storage in Central Sichuan is generally greater than 50 × 104 t/km2 at P50 probability level, with Xujiahe group being the main reservoir. CO2 storage potential of depleted gas fields is 53.73 × 108 t, while it is 33.85 × 108 t by using CO2-EGR technology. This paper recommended that early implementation of CGUS could be carried out in the deep saline aquifers and depleted gas fields in the Sichuan Basin, especially that of the latter because of excellent traps, rich geological data, and well-run infrastructures.

Well selection in depleted oil and gas fields for a safe CO2 storage practice: A case study from Malaysia

Abstract Carbon capture and sequestration technology is recognized as a successful approach taken to mitigate the amount of greenhouse gases released into the atmosphere. However, having a successful storage practice requires wise selection of suitable wells in depleted oil or gas fields to reduce the risk of leakage and contamination of subsurface resources. The aim of this paper is to present a guideline which can be followed to provide a better understanding of sophisticated wells chosen for injection and storage practices. Reviewing recent studies carried out on different aspects of geosequestration indicated that the fracture pressure of seals and borehole conditions such as cement-sheath integrity, distance from faults and fractures together with the depth of wells are important parameters, which should be part of the analysis for well selection in depleted reservoirs. A workflow was then designed covering these aspects and it was applied to a depleted gas field in Malaysia. The results obtained indicated that Well B in the field may have the potential of being a suitable conduit for injection. Although more studies are required to consider other aspects of well selections, it is recommended to employ the formation integrity analysis as part of the caprock assessment before making any decisions.

Geomechanical effects of CO2 storage in depleted gas reservoirs in the Netherlands: Inferences from feasibility studies and comparison with aquifer storage

In this paper, the geomechanical impact of large-scale carbon dioxide (CO2) storage in depleted Dutch gas fields is compared with the impact of CO2 storage in saline aquifers. The geomechanical behaviour of four potential CO2 storage sites is examined using flow and geomechanical simulations. Many gas reservoirs in the Netherlands are found in fault blocks, one to a few kilometres wide, laterally bounded by sealing faults. Aquifer depletion or re-pressurization in the lateral direction is seldom an issue because of a lack of active aquifers. Reservoir pressure changes are therefore limited to a gas-bearing fault block, while the induced stress changes affect the gas reservoir and extend 1–3 km away into the surrounding rock. Arguments in favour of CO2 storage in depleted gas fields are: proven seal quality, availability of field data, no record of seal integrity failure by fault reactivation from the seismically active producing Dutch gas fields, and the potential benefits of restoring the virgin formation pressure and stress state to geomechanical stability. On the other hand, CO2 injection in saline aquifers causes pressure build-up that exceeds the virgin hydrostatic pressure. Stress perturbations resulting from pressure build-up affect large areas, extending tens of kilometres away from the injection wells. Induced stresses in top seals are, however, small and do not exceed a few tenths of megapascal for a pressure build-up of a few megapascals in the storage formation. Geomechanical effects on top seals are weak, but could be enhanced close to the injection zone by the thermal effects of injection. Uncertainties related to characterisation of large areas affected by pressure build-up are significant, and seal quality and continuity are more difficult to be demonstrated for aquifers than for depleted gas reservoirs that have held hydrocarbons for millions of years.

Differences in the public perception of CCS in Germany depending on CO2 source, transport option and storage location

One of the factors decelerating a further diffusion of the carbon capture and storage (CCS) technology is the public’s negative perception of early pilot or demonstration activities in Germany as well as in other countries. This study examined the public perception of CCS in more detail by looking into different options within the CCS chain, i.e. for the three elements capture, transport and storage. This was analyzed using an experimental approach, realized in an online survey with a representative German sample of 1830 citizens. Each participant evaluated one of 18 different CCS scenarios created using three types of CO2 source (industry, biomass, coal), two transport options (pipeline vs. no specification), and three storage possibilities (saline aquifer, depleted gas field, enhanced gas recovery (EGR)).Overall, we found that the ratings of CCS were neutral on average. However, if the CO2 is produced by a biomass power plant or industry, CCS is rated more positively than in a scenario with a coal-fired power plant. The specifications of transport and storage interacted with each other such that scenarios including EGR or a depleted gas field without mentioning a pipeline were evaluated better than storing it in a saline aquifer or a depleted gas field and mentioning a pipeline as means of transport. Exploratory regression analyses indicate the high relevance of the respective CO2 source in general as well as the perceived importance of this source for Germany.

Subsidence Modeling Validation Through Back Analysis for an Italian Gas Storage Field

The multi-disciplinary work described in the paper was aimed at analyzing and predicting the cyclical ground surface movements induced by underground gas storage (UGS) activities in a depleted gas field located in the Po Plain (Italy). The field has been operated as a storage facility for nearly three decades. Currently, the possibility of delta-pressuring the reservoir (i.e. to increase the maximum operating pressure above the initial reservoir pressure) to enhance the storage performance is being considered. Significant information was collected over time: 2/3D seismic surveys, geological and sedimentological studies, 60+ logged wells, geotechnical lab tests and 50+ years of production history and monitoring were available for the development of a fully integrated static–dynamic–geomechanical analysis. The mechanical aspects of the study are the focus of this paper. The data coming from different sources at different scales were analysed and integrated to set up and characterize a 3D finite element method mechanical model to calculate the surface movements induced by UGS activity by adopting an elasto-plastic constitutive law. The model was then calibrated via a back analysis approach, i.e. the model parameters were fine-tuned so that the simulated subsidence/uplift would compare satisfactorily with the ground movements collected over nearly 10 years of monitoring via interferometric synthetic aperture radar analysis in the region under investigation. Eventually, the calibrated model was used as a forecasting tool for subsidence evaluation under different future storage strategies, including delta-pressuring conditions. Results proved that no significant subsidence is expected even if the maximum operating pressure reached 120 % of the initial formation pressure.

Resolving complex communication beyond geological and geophysical data resolution: an example from an underground gas storage facility in the Austrian Molasse Basin

A fully integrated reservoir modelling approach aiming for the best conditioned static model for an underground gas storage facility (UGSF) in a complex structural and depositional setting is presented. The Nussdorf UGSF is a depleted gas field characterized by typical deep-water depositional environment settings including sediment mass-flow systems being shed off the emerging Alpine thrust front during the Neogene. The key challenge in assessing this specific storage performance is the communication within the individual stacked sandstone layers, as well as determining the existing cross-flow between such layers through wells and due to juxtaposition across faults. Highly heterogeneous reservoir facies, representing thin-layered, stacked sandy fans embedded in marly shale, were realized by joining object-based and Gaussian simulations constrained by a gross depositional environment model. Modelling known pressure communication across intrareservoir faults required fault throws to be adjusted at scales below the limit of seismic resolution. Scoping simulation runs on a best-guess model led to a full back-loop of the geological modelling. Several loops revealed that iterations limited to property realizations were insufficient, requiring additional modifications of the structural model. Only via this expensive approach could a geologically consistent and ‘fit for purpose’ reservoir model for the UGSF be achieved.

Carbon dioxide sealing capacity: Textural or compositional controls? A case study from the Oklahoma Panhandle

One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide injected in the repository overcomes the caprock sealing capacity, leaking of may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1) texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2) composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.

Subsidence above depleted gas fields

Purpose– The purpose of this paper is to give an explanation of the new data available about surface subsidence above the depleted gas reservoir Ravenna Terra. These data confirm the existence after end of exploitation of a reversed subsidence bowl with minimum subsidence above the reservoir, as opposed to conventional subsidence bowls during exploitation which show maximum subsidence in the same location.Design/methodology/approach– The paper analyses these new data about the existence after end of exploitation of a reversed subsidence bowl. The observed behaviour is reproduced successfully with a fully coupled two phase flow code in deforming reservoir rocks which incorporates a constitutive model for partially saturated porous media.Findings– The paper provides successful simulations. These allow affirming with confidence that the explanation for the peculiar behaviour is reservoir flooding and partially saturated rock behaviour.Research limitations/implications– Further research: other case studies where similar behaviour is expected, e.g. Ekofisk.Practical implications– The paper includes implications for better management of reservoir exploitation schedules to minimize the observed phenomenon.Originality/value– This paper explains the peculiar behaviour of subsidence above the depleted gas reservoir Ravenna Terra and confirms the conjecture that constitutive behaviour of partially saturated rocks is the origin of the observed phenomenon.

Chemical effects of sulfur dioxide co-injection with carbon dioxide on the reservoir and caprock mineralogy and permeability in depleted gas fields

The most suitable candidates for subsurface storage of CO2 are depleted gas fields. Their ability to retain CO2 can however be influenced by the effect which impurities in the CO2 stream (e.g. H2S and SO2) have on the mineralogy of reservoir and seal. In order to investigate the effects of SO2 we carried out laboratory experiments on reservoir and cap rock core samples from gas fields in the northeast of the Netherlands. The rock samples were contained in reactor vessels for 30days in contact with CO2 and 100ppm SO2 under in-situ conditions (300bar, 100°C). The vessels also contained brine with the same composition as in the actual reservoir. Furthermore equilibrium modeling was carried out using PHREEQC software in order to model the experiments on caprock samples.After the experiments the permeability of the reservoir samples had increased by a factor of 1.2–2.2 as a result of dissolution of primary reservoir minerals. Analysis of the associated brine samples before and after the experiments showed that concentrations of K, Si and Al had increased, indicative of silicate mineral dissolution.In the caprock samples, composed of carbonate and anhydrite minerals, permeability changed by a factor of 0.79–23. The increase in permeability is proportional to the amount of carbonate in the caprock. With higher carbonate content in comparison with anhydrite the permeability increase is higher due to the additional carbonate dissolution. This dependency of permeability variations was verified by the modeling study. Hence, caprock with a higher anhydrite content in comparison with carbonate minerals has a lower risk of leakage after co-injection of 100ppmv SO2 with CO2.

Application of tracers to measure, monitor and verify breakthrough of sequestered CO2 at the CO2CRC Otway Project, Victoria, Australia

At the Cooperative Research Centre for Greenhouse Gas Technology's (CO2CRC) field site in the Otway Basin of Victoria, Australia, investigations into the storage of CO2-rich gas in a depleted hydrocarbon gas field have been conducted in the Waarre C reservoir. The injected gas from the nearby Buttress field contained 75mol% CO2, 21mol% CH4 with the remaining balance being a mixture of wet hydrocarbons, condensate and nitrogen. Chemical tracers (sulphur hexafluoride, SF6; krypton, Kr; perdeuterated methane, CD4) were added on the basis of literature surveys and small volume trials at the Frio II Brine experiment in Texas. The aim of the project was to measure, monitor and verify the presence of injected CO2 in a depleted gas field and that the arrival of tracers was a major component of demonstrating breakthrough of CO2 at the monitoring well, Naylor-1. The paper focuses on methods developed for the injection, recovery and analysis of samples collected at the Naylor-1 well. Results of tracer analysis compare well with other data collected (including pH and density measurements) to demonstrate breakthrough.A slip-stream injection system was designed to deliver the tracers mixed with the CO2-rich gas into the subsurface at the CRC-1 well. The tracers were added to the gas stream 17days after the start of injection (CO2 injection commenced 18th March, 2008) into the depleted natural gas field at Naylor. A U-tube system was used to retrieve the samples from the Naylor-1 monitoring well. Collected gas and formation water samples were analysed in detail for gas composition, tracers, isotopes (13C CO2 mainly) and inorganic geochemistry for the broader project. The tracer results confirm that CO2 breakthrough at the monitoring well occurred within the predicted times. However the interval between samples taken from the U-tubes was too coarse to resolve detailed differences in arrival times between the CO2 and tracers.Of the three tracers used, SF6 provided the clearest evidence of breakthrough at U-tube 2. Kr, because of its abundance in air, and its potential to be present in the subsurface, was more prone to contamination and had higher background levels prior to breakthrough. CD4 was expected to provide some more unique data based on the presence of abundant CH4 in the reservoir interval. With hindsight, larger volumes should have been injected to facilitate comparisons with the other tracers and add value to the data set. The test of CD4 however acted as a suitable proof of concept that CD4 could be used in such a high background of CH4.Further work is ongoing to generate data for partition coefficients between supercritical CO2, CH4 and water under the injection conditions.

Investigation of the interaction of reservoir sections with different permeability in depleted gas field

Investigation of the interaction of reservoir sections with different permeability in depleted gas field

Geochemical evaluation of CO2 injection and containment in a depleted gas field

The short- and long-term geochemical impact of CO2 injection into a depleted gas reservoir (DGR) is investigated using reservoir/geochemical modeling with TOUGH2/TOUGHREACT and 1D kinetic diffusion modeling with PHREEQC (caprock/well-cement). Simulations of CO2 injection into the reservoir predict displacement and buoyancy of post-production CH4, as well as dry-out of the near-well zone. We computed that the areal extent of the CH4/brine dominated zone and the dry-out zone are relatively small compared to the CO2/brine dominated zone after well-closure. For the current DGR model we therefore conclude that it is reasonable to model geochemical reactions in the reservoir without taking into account post-production CH4. Although the CO2 dissolution capacity of the studied DGR is smaller compared to a deep saline aquifer of similar size, the modeling predicts that dissolution and subsequent CO2 mineral trapping proceed faster. Precipitation of dawsonite and magnesite were yet predicted at initial CO2 partial pressure (PCO2) of 9.3bar, while these minerals were not identified in reservoir samples. This could indicate that their tendency of precipitation is overestimated by the model and hence the database used. This has significant impact on long-term modeled bulk porosity and PCO2. Simulations of CO2 diffusion through the caprock show that mineral reactions significantly retard the total dissolved carbon (TDC) plume. After 10,000 years, 99% of the TDC is present within the first 6.4m above the reservoir contact. The progression of the TDC plume in the caprock is sensitive to the composition, kinetic rates, and surface area of primary and secondary minerals. Cement alteration modeling shows progressive carbonation of cement phases, resulting in three zones of distinct mineralogy and porosity. The three zones are predominantly characterized by: (i) unaltered cement, (ii) portlandite dissolution, and (iii) calcite precipitation. The simulated thickness of the affected zone is 3.8cm after 100 years. This distance is sensitive to kinetic rate constants of C–S–H phases, but less sensitive to kinetic rate constant of portlandite. In summary, our applied methodology provides quantitative predictions of the geochemical impact of CO2 on the DGR storage complex. The methodology can be used for screening of potential DGR storage locations and to define criteria for minimal caprock and cement sheet thickness, for assuring short- and long-term integrity of the storage location.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

Coupled hydromechanical analysis of an underground compressed air energy storage facility in sandstone

The underground storage of compressed air is a favourable and low-cost option for balancing off-peak electricity demands. Large volumes of air can be compressed and stored in the ground during low-demand electricity periods, and this pressurised air can then be released to generate electricity during high-demand times. Excavated caverns (generally in salt rock), depleted gas fields and abandoned/excavated mines are the main options typically considered in the design of a compressed air energy storage (CAES) facility. The storage of compressed air in aquifers is a new alternative that has been studied recently. The natural formations around a CAES facility are subjected to significant perturbations in hydraulic and mechanical fields. This paper presents an analysis of a CAES project in an aquifer using a fully coupled hydromechanical framework with the ability to consider the main physical phenomena that control the behaviour of this kind of system. The case study is based on an actual planned CAES project in Iowa, USA. Particular attention was paid to changes in the hydraulic and mechanical fields induced by the operational phases anticipated in a CAES project and to the impact of porosity heterogeneities on system performance. The analysis confirmed that the site is not suitable for a CAES plant.