Depleted Hydrocarbon Reservoirs Research Articles

Well-Integrity Risk-Assessment Strategy Applied to CO2 Sequestration Project

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22348, “Scrutinizing Well Integrity for Determining Long-Term Fate of a CO2 Sequestration Project: An Improved and Rigorous Risk-Assessment Strategy,” by Parimal A. Patil, SPE, Asyraf M. Hamimi, and M. Azuan B. Abu Bakar, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but a high density of wells penetrating the carbon dioxide (CO2) storage reservoir could compromise containment performance in a carbon capture and sequestration (CCS) project. A risk-management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term viability of CO2 sequestration projects. The complete paper evaluates well-integrity and CO2 leakage risks along the wells in a depleted field that penetrates the CO2 storage reservoir. Background The identified CO2 storage site offshore Malaysia is a depleted hydrocarbon field discovered in the early 1980s. Subsequently, two appraisal wells were drilled to further assess the field’s development potential. The structure is a north/south anticline with an aerial extent of approximately 35 km2 and a vertical closure of 100 m on top of the reservoirs. Eighteen major and minor gas-bearing reservoirs exist in the field. The hydrocarbons from deeply buried reservoirs were produced over a period of approximately 15 to 25 years through deviated wellbores. In total, 24 wells are in the targeted field; of these, three are abandoned exploration and appraisal wells and 21 are development wells drilled from the platform. All exploration and appraisal wells are P&A, while 21 development wells are still accessible from the platform. High uncertainties are associated with the P&A wells because the well sites were restored per a regulatory requirement in which the casings were cut below mudline and a surface cement plug was placed with no intention of re-entering these wells. Development wells, on the other hand, were assessed and screened for reuse by conversion into CO2 injectors. Understanding Well Integrity for CO2 Storage Potential leakages that may occur through various mechanisms during geological storage of CO2 in the storage field include failed caprock and trap integrity and leakage along existing wellbores. Parameters that could cause leakage of CO2 because of failed caprock include existing faults or fractures, reactivation of faults, development of new fractures during injection, and caprock failure caused by pressures exceeding fracture pressure during or after injection. The geological analysis of the depleted field for potential development as a future CO2 storage site must understand and mitigate associated risks by integrating information from various databases. However, the integrity of wells in the storage project must be ensured over very long time scales, in the thousands of years.

Three-Way Coupled Modeling Evaluates CO2 Sequestration in Depleted Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206156, “Importance of Three-Way Coupled Modeling for Carbon-Dioxide Sequestration in a Depleted Reservoir,” by Prasanna Chidambaram, SPE, Pankaj K. Tiwari, SPE, and Parimal A. Patil, SPE, Petronas, et al. The paper has not been peer reviewed. _ Three major depleted gas reservoirs in the Central Luconia field offshore Sarawak, Malaysia, are being evaluated for future carbon-dioxide (CO2) storage. A three-way coupled modeling approach that integrates dynamic, geochemistry, and geomechanics models is used to obtain the cumulative effect of all three changes. This integrated model provides a more-accurate estimate of CO2 storage capacity, caprock-integrity evaluation, CO2-plume migration path, and volume of CO2 stored through different mechanisms. Background The CO2 storage sites being evaluated are depleted gas reservoirs that have been in production for a few decades. At the end of their producing life, they have the potential to be converted into CO2 storage sites. The Central Luconia sedimentary basin is in a seismic-free zone with limited faults and consists of shale interbedded with high-sand-content sediment, making it ideal for CO2 storage. These reservoirs provide the required geological characteristics and volume needed to ensure long-term CO2 storage in a safe and economical way. The depleted gas reservoirs have an in-place volume of approximately 1.5–3 Tscf. Their thickness ranges from 100 to 150 m, with a porosity of 15–32% and permeability of 10–1600 md. These fields are believed to be supported by a regional aquifer several thousand feet thick. Large seafloor subsidence has been observed in these reservoirs. Storage-Capacity Estimation Storage capacity of a depleted hydrocarbon reservoir is affected by several factors including voidage created; aquifer influx and efflux during the production and CO2-injection phases, respectively; maximum injection pressure; rock compressibility; and geochemical effects. Depending on which of these factors are prominent in the storage reservoir, CO2-storage capacity may be estimated using a simple material-balance model or may require a more-complex approach to capture these effects. Use of the Three-Way Coupled Model Injected CO2 is anticipated to react with reservoir rock, leading to either dissolution of reservoir rock or precipitation of solids that are products of the geochemical reactions, causing a net change in porosity and permeability. With regard to geomechanical effects, uplift is anticipated to occur during CO2 injection. The degree to which subsidence is reversed depends on whether compaction of the reservoir is fully elastic or if plastic deformation has occurred. During production, reduction in porosity and permeability has occurred because of subsidence. Conventional or stand-alone reservoir simulation does not capture geochemical and geomechanical effects. Hence, it is critical to use an integrated model that captures the effects of dynamic, geochemical, and geomechanical changes caused by CO2 injection in order to evaluate suitability of the reservoir for long-term CO2 storage. A three-way coupled modeling approach that integrates dynamic, geochemistry, and geomechanics models provides a more-accurate estimate of CO2 storage capacity, along with estimation of subsidence. In three-way coupled modeling, the dynamic model is at the center, which passes input parameters to the geochemical and geomechanical models. Once it receives updated porosity and permeability values back from the geochemical and geomechanical models, the dynamic model incorporates these changes before proceeding to the next simulation timestep.

Experimental investigation of hydrogen-carbonate reactions via computerized tomography: Implications for underground hydrogen storage

The underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs, aquifers, and saline caverns is regarded as a vital component of hydrogen economy value-chains, meant to tackle carbon emissions and global warming. The caprock integrity and storage capacity of the carbonate formations can be altered by the reaction between the injected hydrogen and the calcite/dolomite minerals during UHS. However, experimental investigations of hydrogen-calcite/dolomite reactions at underground storage temperature are rarely reported in literature. Thus, we conducted X-ray computed micro-tomography (μCT) scans of limestone and dolomite cores before and after pressurization with hydrogen for 75 days at 700 psi and 75 °C. For the first time, a significant calcite expansion was observed and led to reduction in storage capacity (i.e., effective porosity) by 47%. However, the storage capacity of the dolomite rock slightly increased (∼6%) because the grain expansion effects canceled out the dissolution effects. The study suggests that reduction in storage capacity of carbonate formation due to hydrogen reactivity with calcite is possible during UHS in carbonate formations. Thus, hydrogen reactivity with carbonate minerals should be evaluated to de-risk hydrogen storage projects in carbonate formations.

Impact of Dilation and Irreversible Compaction on Underground Hydrogen Storage in Depleted Hydrocarbon Reservoirs

Underground hydrogen gas storage (UHS) at depleted hydrocarbon reservoirs may balance energy production/consumption during seasons by utilizing the capability of hydrogen gas. The geomechanical behavior of the reservoir rock during UHS operation cycles is an effective parameter of the overall quality and quantity of this operation. This study investigated the impact of rock geomechanical behavior on the quality and quantity of UHS operation performance in a depleted oil reservoir. Three geomechanical behaviors, namely, elastic deformation, irreversible compaction of rock, and dilation–recompaction, form the basis of this study. We numerically investigated how these cases affect wellbore injectability, hydrogen recovery, production of in situ reservoir fluids, and the number of hydrogen injection/production wells. Based on the results of this study, the performance of wells during the injection of hydrogen in the dilation case was better than in other cases. After 10 cycles, 87% of the designed cumulative volume of hydrogen was injected into the reservoir. Though the irreversible compaction case injected the least cumulative hydrogen, it generated the highest hydrogen recovery during annual cycles and at the end of UHS operation (93%). The production of nonhydrogen fluids is known as a problem in UHS operations in depleted hydrocarbon reservoirs. After 10 cycles of hydrogen injection and production and 3 years of prolonged production, the dilation case produced less water and oil overall than other cases. Also, fewer wells are required to achieve the designed injection amount in the dilation case compared to base and irreversible compaction cases. Therefore, the costs associated with hydrogen injection and production wells in reservoirs with geomechanical dilation behavior are lower.

Toward underground hydrogen storage in porous media: Reservoir engineering insights

Subsurface hydrogen storage in depleted hydrocarbon reservoirs and saline formations is a potential option for storing hydrogen at large scales. These subsurface formations need to store sufficient hydrogen efficiently and securely, and the hydrogen must be withdrawn in adequate quantities on demand. In this study, we investigate the reservoir, geological, and operational controls that enable large-scale hydrogen storage and maximize hydrogen injection and withdrawal from depleted natural gas reservoirs. Hydrogen injection, storage, and withdrawal scenarios were computed using a reservoir simulator. Sensitivity analyses exposed the crucial parameters to achieve the goal of optimum storage and withdrawal of hydrogen. We determined that reservoirs with smaller pressures at the start of storage operations are suitable for hydrogen storage if wellhead pressure constraints permit. Steeply dipping reservoirs enable better hydrogen withdrawal if the reservoirs have good permeability (greater than 100 mD) and the injection/withdrawal well is placed updip within the reservoir. Permeable reservoirs and reservoirs with sufficient thickness increase hydrogen withdrawal rates. These findings and the results of the sensitivity analyses are used to propose site selection criteria for underground storage of hydrogen in depleted gas reservoirs.

Cushion and working gases mixing during underground gas storage: Role of fractures

Underground gas storage can help realize sustainable energy supply. This process is based on two main elements, namely cushion gas (CG), which serves to retain the reservoir pressure, and the working gas (WG). In a depleted hydrocarbon reservoir, the required base gas constitutes a large portion of total stored gas. Given the high cost of the base gas for a gas storage project, attempts have been made to reduce this cost by replacing some of the base gas by some less expensive alternative. The main challenge arising from such a replacement is that the CG and WG may mix together, with the mixture exhibiting a lower heat value (HV). In this process, reservoir heterogeneity and fractures, in particular, affect the mixing of the two gases significantly. In this research, the effect of fractures and relevant mechanisms in the replacement of the CG and its mixing with the WG in natural gas storage were numerically simulated. The presence of fracture in the reservoir was found to result in three different behaviors in three different time windows. During early days of production, the fractured reservoir produces a gas of a higher HV than that retrieved from the conventional reservoir. Continuing the production process, however, sets the scene for ending up with a higher HV for the gas retrieved from the conventional reservoir rather than the fractured reservoir. The presence of fractures contributes to the sweeping phenomenon in early production stages but rather boosts the gas mixing effect (GME) in the late production stages, while the sequence is reversed when a conventional reservoir is concerned. A comparison between the CO2 and N2 as alternative CGs showed that the N2 tended to disperse in more layers of the reservoir in presence of fractures, resulting in higher degrees of GME across the reservoir.

Criteria and workflow for selecting depleted hydrocarbon reservoirs for carbon storage

Carbon capture and sequestration (CCS) is playing a role in mitigating carbon emissions and that role is expected to grow dramatically with time. Clustering CO2 sources and sinks through hubs is one way to achieve large-scale deployment of CCS and widespread decarbonization of the energy sector. A key element to the success of hub projects is finding a suitable sequestration site to store these combined emissions. In this study, a quantitative, criteria-driven methodology was developed to assess the potential suitability of depleted oil and gas reservoirs for carbon storage. The methodology utilizes a three-stage process that screens, ranks, and characterizes potential sites based on three categories: (1) capacity and injectivity optimization, (2) retention and geomechanical risk minimization, and (3) siting and economic constraints. Many potential sites are assessable using this methodology until an optimal depleted reservoir, or geographically adjacent set of reservoirs, is identified. The framework is designed to provide insights into the suitability of depleted reservoirs in a variety of different geological environments as well as to be adaptable to a project’s specifications. Specifically, the criteria-driven workflow was applied to fields in the Gulf of Mexico and screened 1,317 fields to identify 10 clusters of 31 fields for further assessment and then ranked those fields and clusters to identify the most suitable sites for secure storage.

Feasibility of hydrogen storage in depleted hydrocarbon chalk reservoirs: Assessment of biochemical and chemical effects

Hydrogen storage is one of the energy storage methods that can help realization of an emission free future by saving surplus renewable energy for energy deficit periods. Utilization of depleted hydrocarbon reservoirs for large-scale hydrogen storage may be associated with the risk of chemical/biochemical reactions. In the specific case of chalk reservoirs, the principal reactions are abiotic calcite dissolution, acetogenesis, methanogenesis and biological souring. Here, we use PHREEQC to evaluate the dynamics and the extent of hydrogen loss by each of these reactions in hydrogen storage scenarios for various Danish North Sea chalk hydrocarbon reservoirs. We find that: (i) Abiotic calcite dissolution does not occur in the temperature range of 40-180° C. (ii) If methanogens and acetogens grow as slow as the slowest growing methanogens and acetogens reported in the literature, methanogenesis and acetogenesis cannot cause a hydrogen loss more than 0.6% per year. However, (iii) if they proceed as fast as the fastest growing methanogens and acetogens reported in the literature, a complete loss of all injected hydrogen in less than five years is possible. (iv) Co-injection of CO2 can be employed to inhibit calcite dissolution and keep the produced methane due to methanogenesis carbon neutral. (v) Biological sulfate reduction does not cause significant hydrogen loss during 10 years, but it can lead to high hydrogen sulfide concentrations (1015 ppm). Biological sulfate reduction is expected to impact hydrogen storage only in early stages if the only source of sulfur substrates are the dissolved species in the brine and not rock minerals. Considering these findings, we suggest that depleted chalk reservoirs may not possess chemical/biochemical risks and be good candidates for large-scale underground hydrogen storage.

Assessment of CO2 storage potential in reservoirs with residual gas using deep learning

[Formula: see text] injection into the underlying water leg of depleted hydrocarbon reservoirs is a desirable option for carbon storage as demonstrated by existing industrial-scale storage projects in these geologic environments. This study sheds light on the effect of residual methane on the [Formula: see text] storage efficiency as a screening criterion for selecting a water-bearing zone of a depleted gas reservoir to store [Formula: see text]. Using compositional reservoir simulations, we have evaluated the impact of residual methane on the injectivity, operational pressure, and long-term [Formula: see text] trapping efficiency during injection and postinjection stage in a reservoir model representative of the so-called “HC sand” gas reservoir in the High Island 24L field located in the offshore Texas State Waters. Results suggest that the presence of residual hydrocarbon gas negatively affects [Formula: see text] residual and dissolution trapping because it enhances the injectivity and pressure management arising from the increased mobility of [Formula: see text] plume in the vicinity of the injection zone due to its mixing with the resident residual hydrocarbon gas. We further investigate the application of artificial neural network (ANN)-based proxy models for fast-track modeling of [Formula: see text] storage in geologic structures associated with depleted gas reservoirs, aiming at the prediction of [Formula: see text] trapping efficiency. We then use the developed ANN model to perform Monte Carlo simulations for quantifying the uncertainty of geologic and reservoir parameters on [Formula: see text] trapping efficiency in these formations. It becomes evident that the residual hydrocarbon saturation is a key screening criterion for the storage site selection. The developed data-driven model can offer a robust and fast tool for screening the water-bearing zone of the depleted gas reservoirs by evaluating the efficiency of [Formula: see text] storage.

Multidisciplinary Assessment of a Novel Carbon Capture and Utilization Concept including Underground Sun Conversion

The current work investigates the feasibility of a novel Carbon Capture and Utilization (CCU) approach—also known as Underground Sun Conversion (USC) or geo-methanation. The overall objective of the current work is a comprehensive assessment on the technical, economic and legal aspects as well as greenhouse gas impacts to be concerned for establishing USC technology concept. This is achieved by applying multidisciplinary research approach combining process simulation, techno-economic and greenhouse gas assessment as well as legal analysis allows answering questions about technical, economic feasibility and greenhouse gas performance as well as on legal constraints related to large scale CCU using geo-methanation in depleted hydrocarbon reservoirs. CO2 from the industry and renewable H2 from the electrolyser are converted to geomethane in an underground gas storage and used in industry again to close the carbon cycle. Process simulation results showed the conversion rates vary due to operation mode and gas cleaning is necessary in any case to achieve natural gas grid compliant feed in quality. The geomethane production costs are found to be similar or even lower than the costs for synthetic methane from Above Ground Methanation (AGM). The GHG-assessment shows a significant saving compared to fossil natural gas and conventional power-to-gas applications. From a legal perspective the major challenge arises from a regulative gap of CCU in the ETS regime. Accordingly, a far-reaching exemption from the obligation to surrender certificates would be fraught with many legal and technical problems and uncertainties.

Mechanistic simulation of cushion gas and working gas mixing during underground natural gas storage

One of the approaches to sustainable energy supply is underground natural gas storage (UGS). In UGS, the gas in the underground storage is made up of two fractions, namely base gas (cushion gas) and working gas. The base gas is injected into the reservoir to maintain the pressure and stays there until the end of the storage period. Depending on the underground structure of the storage reservoir, base gas constitutes 15 – 75% of total gas stored in the storage reservoir. This implies that a large fraction of the required gas for storage into a depleted hydrocarbon reservoir, which is the most popular form of structures for UGS, is the base gas. Therefore, supplying the base gas incurs high costs for a UGS project. In order to reduce the cost of base gas, alternative less-expensive gasses are practically used as base gas; such as nitrogen and carbon dioxide. The main challenge ahead of developing this replacement is the cushion and working gas mixing and the resultant decrease in the heat value of the produced gas. In this paper, effects of molecular diffusion, operating conditions, reservoir, and rock properties on the replacement of cushion gas in conventional reservoirs were investigated, using mechanistic numerical simulation. Effect of cushion and working gas mixing on the gas quality profile during production cycle were addressed as a first time. Based on the results, we found that, with increasing the vertical permeability and compressibility of the reservoir rock, the cushion and operating gas mixing increases, thereby degrading the heat value of the produced gas. In general, the cushion and operating gas mixing was seen to decrease with porosity but rather increase with temperature. An increase in initial reservoir pressure increases the gas mixing in the early stages of production while decreasing it at later stages of production. In early stage of production from the reservoir, an increase in the stored volume of gas decreases the gas mixing effect. As the time passes and the cushion gas reaches the near-well zone, however, the same change in stored volume tends to increase the gas mixing effect. Comparing carbon dioxide with nitrogen as alternative cushion gas, the carbon dioxide was seen to result in lower gas mixing.

Rapid microbial methanogenesis during CO2 storage in hydrocarbon reservoirs

Carbon capture and storage (CCS) is a key technology to mitigate the environmental impact of carbon dioxide (CO2) emissions. An understanding of the potential trapping and storage mechanisms is required to provide confidence in safe and secure CO2 geological sequestration1,2. Depleted hydrocarbon reservoirs have substantial CO2 storage potential1,3, and numerous hydrocarbon reservoirs have undergone CO2 injection as a means of enhanced oil recovery (CO2-EOR), providing an opportunity to evaluate the (bio)geochemical behaviour of injected carbon. Here we present noble gas, stable isotope, clumped isotope and gene-sequencing analyses from a CO2-EOR project in the Olla Field (Louisiana, USA). We show that microbial methanogenesis converted as much as 13–19% of the injected CO2 to methane (CH4) and up to an additional 74% of CO2 was dissolved in the groundwater. We calculate an in situ microbial methanogenesis rate from within a natural system of 73–109 millimoles of CH4 per cubic metre (standard temperature and pressure) per year for the Olla Field. Similar geochemical trends in both injected and natural CO2 fields suggest that microbial methanogenesis may be an important subsurface sink of CO2 globally. For CO2 sequestration sites within the environmental window for microbial methanogenesis, conversion to CH4 should be considered in site selection.

CO2 storage algorithms involving the hybrid geological reservoir of the Irati Formation, Parana Basin

The injection and permanent storage of carbon dioxide (CO2) in depleted hydrocarbon reservoirs is a norm in atmospheric CO2 reduction practices. Currently, in the Irati Formation, there are no hydrocarbon production events; therefore, this study applies detailed petrophysical and seismic evaluations to present the algorithms for predicting CO2 storage potentials of the shale and carbonate reservoirs. There are studies involving the overview of the CO2 storage potential of the study location; however, an exhaustive presentation such as this is novel in the region. It proposes the shale-carbonate hybrid geological reservoir to maximise the storage capacity by reducing the geological constraints associated with thin-bedded layers, inadequate overburdens, water saturation (Sw), fault distributions, total organic content (TOC), and porosity (Ф). It reveals that the geological and other carbon capture and storage (CCS) related parameters presented for the conceived hybrid reservoir conform to the CO2 storage criteria considering the research results and existing atlases. The study shows average values for Ф (8.2% in shale and 13.1% in carbonates), TOC (8.8% in shale and 5.6% in carbonate) and reservoir thickness (13.7 m for shale and 15.4 m for carbonate) involving an estimated area of 4.3 × 109 m2. It presents an average value of 13.0% for Sw at depths ≥950 m, and the estimated CO2 storage capacity of the hybrid geological reservoir is 13.58 Gt. Therefore, the results of this study will assist in making an informed decision concerning the actualisation of CO2 storage within the Irati Formation and related geological units, especially in the absence of pre-determined data from hydrocarbon production.

Quantitatively determine CO2 geosequestration capacity in depleted shale reservoir: A model considering viscous flow, diffusion, and adsorption

Depleted hydrocarbon reservoirs have been gradually recognized as the potential candidates for geological storage of carbon dioxide due to their wide geographical spread and large storage capacity. Reliably assess CO2 geosequestration capacity (CGC) of depleted hydrocarbon reservoirs lays the foundation of CO2 long-term geosequestration security. In this study, a model, considering CO2 viscous flow, diffusion, and adsorption in shale reservoirs, is established to determine bottom-hole pressure during CO2 injection through a hydraulic fractured multiwell-pad. The computational efficient semi-analytical solution is obtained by superposition principle and Laplace numerical inverse technique. Applying the developed model, a workflow is accordingly proposed to evaluate CGC of depleted shale reservoirs. As a case verification, the calculation on the CGC of a depleted shale reservoir from Barnett Shale in Texas is conducted, which illustrates that its CGC reaches up to 3.8 × 1012m3 when the constrained injection pressure (CIP) is high. Moreover, sensitivity analyses suggest that most reservoir parameters exhibit ignorable impacts on CGC when CIP is low whereas their effects on CGC are significant at high CIP. For instance, for the low-CIP, CGC just increases by approximately 6.7% when adsorption index increases from 2.5 to 250. As for the high-CIP scenario, CGC significantly increases 164 times for the same adsorption index range. In contrast to reservoir parameters, engineering parameters generally show great impacts on CGC at low CIP whereas their effects on CGC are negligible when CIP is high. To be more specific, CGC increases by 2.42 times when injection rate ratio of two wells ranges from 8 to 0.5 under low-CIP condition whereas CGC increases just by 0.47 times when CIP is high. The findings obtained in this study pave the way for the long-term CO2 geosequestration in depleted hydrocarbon reservoirs with much less efforts.

Analytical and numerical modeling for the assessment of CO2 storage in the Pariñas geological formation - Talara, Peru

This research evaluates the CO2 storage capacity of the Pariñas Formation belonging to the Talara basin in Peru through analytical modeling based on mass balance equations and numerical modeling using IMEX CMG. Pariñas Formation has several depleted hydrocarbon reservoirs that presents favorable conditions for CO2 geological storage. It has an average porosity of 17.6% and a permeability of 640 mD in the horizontal direction consisting of sandstones with interspersed lutites layers. The study evaluates the depleted Bellavista oil deposits involving CO2 storage capacity estimation with CO2 and reservoir fluid (oil and water) interaction. It involves numerical modeling based on the reservoirs properties and CO2 injection simulation not exceeding the fracture pressure of the reservoir rock. This approach is the first one carried out in Peru and provides the chance to evaluate the CO2 storage capacity in a hydrocarbon reservoir in this part of the world, as a strategy to mitigate future global change impacts. The results indicate a storage capacity of 35.37 million tons of CO2, approximately. Besides, the sandstone reservoir of the Pariñas geological formation has adequate characteristics to serve as a CO2 storage reservoir. C30+ pseudo component shows greater sensitivity in its properties (temperature and critical pressure) adjusting the fluid properties with the experimental data (saturation pressure, viscosity and minimum miscibility pressure).

Machine Learning Provides Effective Leak Detection in Carbon Sequestration Projects

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201552, “Leak Detection in Carbon Sequestration Projects Using Machine Learning Methods: Cranfield Site, Mississippi, USA,” by Saurabh Sinha, SPE, University of Oklahoma and Los Alamos National Laboratory; Rafael Pires De Lima, Geological Survey of Brazil; and Youzuo Lin, Los Alamos National Laboratory, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. Saline aquifers and depleted hydrocarbon reservoirs with good seals located in tectonically stable zones make an excellent storage formation option for geological carbon sequestration.Ensuring that carbon dioxide (CO2) does not leak from these reservoirs is the key to any successful carbon capture and storage (CCS) project. In the complete paper, the authors demonstrate automated leakage detection in CCS projects using pressure data obtained from the Cranfield reservoir in Mississippi in the US. Results indicate that even simple deep-learning architectures such as multilayer feed-forward neural networks (MFNNs) can identify a leak using pressure data. Introduction Several methods that use different types of data currently are available to detect leaks. Although some of the methods are a direct indicator of CO2 presence, they cannot provide an early warning for the leaks, thus delaying remedial measures. An ideal process for the identification of leakages requires constant and repetitive comparisons of different data. Machine-learning (ML) techniques are ideally suited for this task. In this work, the authors demonstrate the use of ML techniques such as linear model, random forest, and MFNN on time-series signals obtained from a pressure-pulse test. The methodology uses the time-series data instead of 2D images or 3D voxels, thus providing a computational advantage. The authors write that an ML algorithm can distinguish between a pressure signal corresponding to a leak vs. the pressure signal corresponding to a baseline nonleak case. The trained models can then be used as an early-warning system to flag anomalous data to then be analyzed by a human interpreter. Background A pressure-pulse test uses at least two wells: an injection well and a monitoring well. The reservoir is then shocked by a series of predetermined cycles of injection and shut-ins (i.e., a pulse). The response then is recorded at the monitoring well with a pressure gauge that measures the target formation pressure. The test may be repeated with different pulses to understand the reservoir properties better. A harmonic pulse is preferred over a square wave because it allows for spectral decomposition of the pulse to analyze the reservoir response at different frequencies. Three wells are used in the study: F1, F2, and F3. Well F1 is the injector well, where alternative cycles of injection of CO2 and shut-in are carried out. Well F2 is the monitor well, which remains shut in for the duration of the test and where the pressure is monitored with the use of a pressure gauge. An artificial leak is simulated in the test by opening a surface valve at Well F3.

The preliminary selection of oil reservoir in Serbia for carbon dioxide injection and storage by a multicriteria decision-making approach: a case study

ABSTRACT One of the current prospective solutions that can contribute to significant carbon dioxide emission mitigation is carbon capture and storage in geological formations. The most challenging issue in underground storage is the provision of safe and long-term storage without possible carbon dioxide leakage. From the safety point of view, it is considered that the most appropriate geological formations for carbon dioxide storage are depleted hydrocarbon reservoirs or partially depleted oil reservoirs, where injection of carbon dioxide enhances oil recovery. This paper proposes a multicriteria decision-making model for preliminary selection of an oil reservoir in Serbia for carbon dioxide injection and storage. Applied multicriteria decision-making methods are ”Technique of order preference similarity to the ideal solution” (TOPSIS) and ”Multicriteria optimization and compromise solution” (VIKOR). In the analyzed multicriteria decision model three alternative oil reservoirs and seven criteria are considered. The evaluation and decision-making process presented in the study includes a selection of the geological formations for storing carbon dioxide and enhancing oil recovery, choosing the criteria and alternatives, the initial decision-making matrix development, weight criteria determination by entropy method, application of multicriteria decision-making methods for ranking alternatives, and comparison of applied methods results. The results of this study show that the same results are obtained by applying these two methods, i.e., oil reservoir A3 is the most appropriate candidate for application of carbon dioxide injection and geological storage.

Engineering design of CO2 storage in saline aquifers and in depleted hydrocarbon reservoirs: similarities and differences

The types of geological structures suitable for CO2 storage are saline aquifers (SA) and depleted hydrocarbon reservoirs (DHR). It is well-known that a direct comparison is often somewhat misleading; the preferences depend on many factors, including availability, logistical and economic concerns. However, advantages and disadvantages in terms of various engineering aspects are often compared. We summarize the state-of-the-art of knowledge on the use of SAs and DHRs. Physical processes involved, analytical and numerical approaches for capacity and injectivity estimations, containment, wellbore and near-wellbore challenges and logistical options are discussed for both options. Comparisons are made considering engineering design for the onshore and offshore cases together with the preliminary economics.

Research on the possibility of using loading materials to support the treatment of reservoir waters

The article presents the issues related to of the removal of suspensions and sediments from reservoir waters. In the conducted research, particular emphasis was placed on the techniques of using loading materials in the water treatment process. The research materials were four types of reservoir water, which was collected from the separators of wells exploiting natural gas deposits. These waters were characterized by high suspended solids (76–176 mg/dm3) and a varied degree of mineralization. The content of dissolved substances was determined in the range from 401 to 306 428 mg/dm3. The extracted reservoir waters are currently most often utilized by pumping into the absorbing horizons in depleted hydrocarbon reservoirs. The preparation of water for injection is limited only to the removal of easily settling solid particles and suspensions present in the extracted formation waters. The porosity and permeability of the deposit rocks determine the size of solid particles present in the water that can be forced into voids in the porous medium. In the process of water treatment by coagulation and flocculation, carried out in laboratory conditions, Flokor ASW was used as a coagulant, while Stabpol was used as a flocculant. Post-coagulation sludge is highly hydrated, so that its density is close to that of water, as a result of which sedimentation of sludge particles takes a long time. In order to increase the sedimentation rate of particles contained in the treated waters, ballasting materials, which were quartz sand and bentonites: powdery bentonite and bentonite preparation DuoBent 1, were successively introduced into the solutions. The effectiveness of the water treatment process was assessed by comparing the degree of turbidity of the solution above the sediment before and after adding a different amount of coagulant, flocculant and sediment-balancing materials. The turbidity measurement of the tested solutions allows to estimate the content of suspensions and colloids in them. Laboratory tests were carried out on the possibility of using selected materials ballasting suspensions in the process of reservoir water treatment. Effective doses of ballast materials recommended for use in the separation of suspensions from formation waters were determined. Research results presented in this paper show that the removal of suspended solids from formation waters can be carried out with the use of a properly prepared bentonite agent (DuoBent 1) with no need of adding other chemical compounds. The doses of the DuoBent 1 bentonite preparation, dosed into highly mineralized reservoir waters in order to remove turbidity, are relatively small. Adding bentonite into the treated waters in amounts exceeding 0.2 g/dm3 results in obtaining high clarity of the water intended for injection (turbidity at the level of 0–5 FAU). The results of the research can be implemented for practical use as a simple method of purifying reservoir water prior to injection into the formation.

How can biogeomechanical alterations in shales impact caprock integrity and CO2 storage?

Shales have been a major focus of the energy industry over the past few decades. Recently, there is a paradigm shift in the energy industry to low-carbon solutions, such as carbon capture and storage (CCS), to mitigate global warming caused by carbon footprint. The problem of long-term safe and efficient geological CO2 storage (GCS) and caprock integrity are some of the major challenges impeding large-scale CCS application. Here, we investigated how localized and bulk biogeomechanical alterations could potentially impact caprock integrity and CO2 storage in depleted shale reservoirs. We cultivated the shale core samples (containing both artificial-induced and pre-existing natural fractures) with a cultured microbial solution at specific temperature, time, and growth conditions. Subsequently, we obtain the properties of the fractured shale rock samples impacted by this microbial process. We investigate the impact of the mechanical responses due to the microbial process, on the long-term integrity and storage potentials of CO2 in shale reservoirs. Our results suggest that in Eagle Ford, Marcellus, and Niobrara shale formations, microbially-altered local and bulk mechanical properties can enhance the long-term caprock integrity and CO2 storage security by: (1.) Increasing the localized (+19% unconfined compressive strength, −20% Poisson’s ratio, +35% fracture toughness) and bulk (+50% unconfined compressive strength, −13% Poisson’s ratio) mechanical integrity; (2.) Decreasing permeability (−93%) and porosity (−38%); (3.) Altering the clay mineral content (−56%), calcite content (+21%), and morphology; (4.) Occluding microfractures; and (5.) Mitigating any potential leakage to the atmosphere through the caprock. This study considers the heterogeneity of shales, and provide valuable insights and viable assessment in solving the long-term GCS application in depleted hydrocarbon reservoirs.