Optimizing Carbon Sequestration With the Capacitance/Resistance Model

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1094-1102 ◽  
Author(s):  
Qing Tao ◽  
Steven L. Bryant
Keyword(s):  
Co2 Storage ◽  
Work Flow ◽  
Co2 Injection ◽  
Attractive Alternative ◽  
Optimal Control Strategy ◽  
Reasonable Estimate ◽  
Storage Reservoirs ◽  
Resistance Model ◽  
Carbon Dioxide Co2 ◽  
Storage Processes

Summary Carbon dioxide (CO2) storage in deep brine-filled structures accompanied by brine extraction has several more advantages than conventional injection-only storage schemes, but avoiding CO2 arrival at extraction wells becomes a paramount concern. The use of conventional reservoir simulators to optimize CO2 injection/brine extraction requires a model of the petrophysical properties of the storage formation. Unfortunately, those properties are unlikely to be adequately characterized in storage reservoirs, especially at the outset of a project. An attractive alternative tool to manage injection/extraction storage processes is the capacitance/resistance model (CRM), which only requires the wells' injection/extraction histories as input. A useful characteristic of CRM for this application is that it identifies the connectivities between injectors and extractors. We show the effectiveness of the method on a homogeneous aquifer with variable injection rates. We describe a work flow that optimizes subsequent CO2 storage in the aquifer with the CRM parameters obtained from the injection/extraction history. A reasonable estimate of CRM parameters requires a sufficient length of injection/extraction history. We present further a dynamic work flow that allows updating the history and the optimal control strategy. The applications on the example storage aquifers show significant improvements in the amount of CO2 stored by injection/extraction strategies.

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

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

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.

Wettability measurements on two sandstones: an experimental investigation before and after CO2 flooding

2020 ◽  
Vol 60 (1) ◽  
pp. 117
Author(s):  
Cut Aja Fauziah ◽  
Emad A. Al-Khdheeawi ◽  
Ahmed Barifcani ◽  
Stefan Iglauer
Keyword(s):  
Contact Angle ◽  
Co2 Storage ◽  
Contact Angle Measurement ◽  
Contact Angles ◽  
Angle Measurement ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Berea Sandstone ◽  
Before And After ◽  
Carbon Dioxide Co2

Wettability of rock–fluid systems is an important for controlling the carbon dioxide (CO2) movement and the capacities of CO2 geological trapping mechanisms. Although contact angle measurement is considered a potentially scalable parameter for evaluation of the wettability characteristics, there are still large uncertainties associated with the contact angle measurement for CO2–brine–rock systems. Thus, this study experimentally examined the wettability, before and after flooding, of two different samples of sandstone: Berea and Bandera grey sandstones. For both samples, several sets of flooding of brine (5 wt % NaCl + 1 wt % KCl in deionised water), CO2-saturated (live) brine and supercritical CO2 were performed. The contact angle measurements were conducted for the CO2–sandstone system at two different reservoir pressures (10 and 15 MPa) and at a reservoir temperature of 323 K. The results showed that both the advancing and receding contact angles of the sandstone samples after flooding were higher than that measured before flooding (i.e. after CO2 injection the sandstones became more CO2-wet). Moreover, the Bandera grey samples had higher contact angles than Berea sandstone. Thus, we conclude that CO2 flooding altered the sandstone wettability to be more CO2-wet, and Berea sandstone had a higher CO2 storage capacity than Bandera grey sandstone.

A Laboratory Study of Coinjection of Water and CO2 to Improve Oil Recovery and CO2 Storage: Effect of Fraction of CO2 Injected

SPE Journal ◽  
2020 ◽  
pp. 1-9
Author(s):  
Emmanuel Ajoma ◽  
Thanarat Sungkachart ◽  
Saria ◽  
Hang Yin ◽  
Furqan Le-Hussain
Keyword(s):  
Oil Recovery ◽  
Laboratory Experiments ◽  
Water Pressure ◽  
Co2 Storage ◽  
Water Injection ◽  
Molar Fraction ◽  
Co2 Injection ◽  
The Core ◽  
Carbon Dioxide Co2 ◽  
Water Saturated

Summary To determine the effect on oil recovery and carbon dioxide (CO2) storage, laboratory experiments are run with various fractions of CO2 injected (FCI): pure CO2 injection (FCI = 1), water-saturated CO2 (wsCO2) injection (FCI = 0.993), simultaneous water and gas (SWAG) (CO2) injection (FCI = 0.75), carbonated water injection (CWI) (FCI = 0.007), and water injection (FCI = 0). All experiments are performed on Bentheimer sandstone cores at 70°C and 11.7 MPa (1,700 psia). The oil phase is composed of 65% hexane and 35% decane by molar fraction. Before any fluid is injected, the core is filled with oil and irreducible water. Pressure difference across the core and production rate of gas are measured during the experiment. The collected produced fluids are analyzed in a gas chromatograph to determine their composition. Cumulative oil recovery after injection is found to be 78 to 83% for wsCO2, 78% for SWAG, 74% for pure CO2, 53% for CWI, and 35% for water. Net CO2 stored is also found to be the highest for wsCO2 (59 to 65% of the pore volume), followed by that for CO2 injection (56%) and that for SWAG (42%). These results suggest that wsCO2 injection might outperform pure CO2 injection at both oil recovery and net CO2stored.

How CO2-Storage Mechanisms Are Different in Organic Shale: Characterization and Simulation Studies

SPE Journal ◽  
2017 ◽  
Vol 23 (03) ◽  
pp. 661-671 ◽  
Author(s):  
Hui Pu ◽  
Yuhe Wang ◽  
Yinghui Li
Keyword(s):  
Flue Gas ◽  
Local Density ◽  
Flow Behavior ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Full Spectrum ◽  
Adsorption Sites ◽  
Novel Approach ◽  
Carbon Dioxide Co2 ◽  
Organic Shale

Summary Widely distributed organic-rich shales are being considered as one of the important carbon-storage targets, owing to three differentiators compared with conventional reservoirs and saline aquifers: (1) trapping of a significant amount of carbon dioxide (CO2) permanently; (2) kerogen-rich shale's higher affinity of CO2; and (3) existing well and pipeline infrastructure, especially that in the vicinity of existing power or chemical plants. The incapability to model capillarity with the consideration of imperative pore-size-distribution (PSD) characteristics by use of commercial software may lead to inaccurate modeling of CO2 injection in organic shale. We develop a novel approach to examine how PSD would alter phase and flow behavior under nanopore confinements. We incorporate adsorption behavior with a local density-optimization algorithm designed for multicomponent interactions to adsorption sites for a full spectrum of reservoir pressures of interests. This feature elevates the limitation of the Langmuir isotherm model, allowing us to understand the storage and sieving capabilities for a CO2/N2 flue-gas system with remaining reservoir fluids. Taking PSD data of Bakken shale, we perform a core-scale simulation study of CO2/N2 flue-gas injection and reveal the differences between CO2 injection/storage in organic shales and conventional rocks on the basis of numerical modeling.

Complete Equation of State Thermal Formulation for Simulation of CO2 Storage

SPE Journal ◽  
2021 ◽  
pp. 1-15
Author(s):  
Arthur Moncorgé ◽  
Martin Petitfrère ◽  
Sylvain Thibeau
Keyword(s):  
Equation Of State ◽  
Co2 Storage ◽  
Continuous Phase ◽  
Conservation Equation ◽  
Co2 Injection ◽  
Energy Conservation Equation ◽  
Carbon Dioxide Co2 ◽  
New Formulation ◽  
Primary Variable ◽  
Phase Envelope

Summary Storage of carbon dioxide (CO2) in depleted gas reservoirs or large aquifers is one of the available solutions to reduce anthropogenic greenhouse gas emissions. Numerical modeling of these processes requires the use of large geological models with several orders of magnitude of variations in the porous media properties. Moreover, modeling the injection of highly concentrated and cold CO2 in large reservoirs with the correct physics introduces numerical challenges that conventional reservoir simulators cannot handle. We propose a thermal formulation based on a full equation of state (EoS) formalism to model pure CO2 and CO2 mixtures with the residual gas of depleted reservoirs. Most of the reservoir simulators model the phase equilibriums with a pressure-temperature-based formulation. With this usual framework, it is not possible to exhibit two phases with pure CO2 contents. Moreover, in this classical framework, the crossing of the phase envelope is associated with a large discontinuity in the enthalpy computation, which can prevent the convergence of the energy conservation equation. In this work, accurate and continuous phase properties are obtained, basing our formulation on enthalpy as a primary variable. We first implement a new phase-split algorithm with input variables as pressure and enthalpy instead of the usual pressure and temperature, and we validate it on several test cases. This algorithm can model situations in which the mixture can change rapidly from one phase to the other at constant pressure and temperature. Then, treating enthalpy instead of temperature as a primary variable in both the reservoir and the well modeling algorithms, our reservoir simulator can model situations with pure or near pure components, as well as crossing of the phase envelope that usual formulations implemented in reservoir simulators cannot handle. We first validate our new formulation against the usual formulation on a problem in which both formulations can correctly represent the physics. Then, we show situations in which the usual formulations fail to represent the correct physics and that are simulated well with our new formulation. Finally, we apply our new model for the simulation of pure and cold CO2 injection in a real depleted gas reservoir from the Netherlands.

scholarly journals A Numerical Analysis of the Effects of Supercritical CO2 Injection on CO2 Storage Capacities of Geological Formations

2020 ◽  
Vol 2 (3) ◽  
pp. 333-364
Author(s):  
Kamal Jawher Khudaida ◽  
Diganta Bhusan Das
Keyword(s):  
Capillary Pressure ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Heterogeneous Aquifers ◽  
The North ◽  
Solubility Trapping ◽  
Aquifer Characteristics ◽  
Carbon Dioxide Co2 ◽  
Supercritical Co2 Injection ◽  
Geological Formations

One of the most promising means of reducing carbon content in the atmosphere, which is aimed at tackling the threats of global warming, is injecting carbon dioxide (CO2) into deep saline aquifers (DSAs). Keeping this in mind, this research aims to investigate the effects of various injection schemes/scenarios and aquifer characteristics with a particular view to enhance the current understanding of the key permanent sequestration mechanisms, namely, residual and solubility trapping of CO2. The paper also aims to study the influence of different injection scenarios and flow conditions on the CO2 storage capacity and efficiency of DSAs. Furthermore, a specific term of the permanent capacity and efficiency factor of CO2 immobilization in sedimentary formations is introduced to help facilitate the above analysis. Analyses for the effects of various injection schemes/scenarios and aquifer characteristics on enhancing the key permanent sequestration mechanisms is examined through a series of numerical simulations employed on 3D homogeneous and heterogeneous aquifers based on the geological settings for Sleipner Vest Field, which is located in the Norwegian part of the North Sea. The simulation results highlight the effects of heterogeneity, permeability isotropy, injection orientation and methodology, and domain-grid refinement on the capillary pressure–saturation relationships and the amounts of integrated CO2 throughout the timeline of the simulation via different trapping mechanisms (solubility, residual and structural) and accordingly affect the efficiency of CO2 sequestration. The results have shown that heterogeneity increases the residual trapping of CO2, while homogeneous formations promote more CO2 dissolution because fluid flows faster in homogeneous porous media, inducing more contact with fresh brine, leading to higher dissolution rates of CO2 compared to those in heterogeneous porous medium, which limits fluid seepage. Cyclic injection has been shown to have more influence on heterogenous domains as it increases the capillary pressure, which forces more CO2 into smaller-sized pores to be trapped and exposed to dissolution in the brine at later stages of storage. Storage efficiency increases proportionally with the vertical-to-horizontal permeability ratio of geological formations because higher ratios facilitate the further extent of the gas plume and increases the solubility trapping of the integrated gas. The developed methodology and the presented results are expected to play key roles in providing further insights for assessing the feasibility of various geological formations for CO2 storage.

Constraining Leakage Pathways Through the Overburden Above Sub-Seafloor Co2 Storage Reservoirs

2019 ◽  
Author(s):  
Jonathan Bull ◽  
Christian Berndt ◽  
Timothy Minshull ◽  
Timothy Henstock ◽  
Gaye Bayrakci ◽  
...  
Keyword(s):  
Co2 Storage ◽  
Storage Reservoirs

scholarly journals Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

2012 ◽  
Author(s):  
Zheming Zhang ◽  
Ramesh Agarwal
Keyword(s):  
Numerical Simulation ◽  
Co2 Sequestration ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Injection Well ◽  
Co2 Injection ◽  
Great Promise ◽  
Saline Aquifer ◽  
Simulation And Optimization ◽  
Co2 Plume

With recent concerns on CO2 emissions from coal fired electricity generation plants; there has been major emphasis on the development of safe and economical Carbon Dioxide Capture and Sequestration (CCS) technology worldwide. Saline reservoirs are attractive geological sites for CO2 sequestration because of their huge capacity for sequestration. Over the last decade, numerical simulation codes have been developed in U.S, Europe and Japan to determine a priori the CO2 storage capacity of a saline aquifer and provide risk assessment with reasonable confidence before the actual deployment of CO2 sequestration can proceed with enormous investment. In U.S, TOUGH2 numerical simulator has been widely used for this purpose. However at present it does not have the capability to determine optimal parameters such as injection rate, injection pressure, injection depth for vertical and horizontal wells etc. for optimization of the CO2 storage capacity and for minimizing the leakage potential by confining the plume migration. This paper describes the development of a “Genetic Algorithm (GA)” based optimizer for TOUGH2 that can be used by the industry with good confidence to optimize the CO2 storage capacity in a saline aquifer of interest. This new code including the TOUGH2 and the GA optimizer is designated as “GATOUGH2”. It has been validated by conducting simulations of three widely used benchmark problems by the CCS researchers worldwide: (a) Study of CO2 plume evolution and leakage through an abandoned well, (b) Study of enhanced CH4 recovery in combination with CO2 storage in depleted gas reservoirs, and (c) Study of CO2 injection into a heterogeneous geological formation. Our results of these simulations are in excellent agreement with those of other researchers obtained with different codes. The validated code has been employed to optimize the proposed water-alternating-gas (WAG) injection scheme for (a) a vertical CO2 injection well and (b) a horizontal CO2 injection well, for optimizing the CO2 sequestration capacity of an aquifer. These optimized calculations are compared with the brute force nearly optimized results obtained by performing a large number of calculations. These comparisons demonstrate the significant efficiency and accuracy of GATOUGH2 as an optimizer for TOUGH2. This capability holds a great promise in studying a host of other problems in CO2 sequestration such as how to optimally accelerate the capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.

scholarly journals Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1557
Author(s):  
Amine Tadjer ◽  
Reidar B. Bratvold
Keyword(s):  
Uncertainty Quantification ◽  
History Matching ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Monitoring Program ◽  
Co2 Injection ◽  
Drinking Water Contamination ◽  
Model Inversion ◽  
Geological Co2 Storage ◽  
And Storage

Carbon capture and storage (CCS) has been increasingly looking like a promising strategy to reduce CO2 emissions and meet the Paris agreement’s climate target. To ensure that CCS is safe and successful, an efficient monitoring program that will prevent storage reservoir leakage and drinking water contamination in groundwater aquifers must be implemented. However, geologic CO2 sequestration (GCS) sites are not completely certain about the geological properties, which makes it difficult to predict the behavior of the injected gases, CO2 brine leakage rates through wellbores, and CO2 plume migration. Significant effort is required to observe how CO2 behaves in reservoirs. A key question is: Will the CO2 injection and storage behave as expected, and can we anticipate leakages? History matching of reservoir models can mitigate uncertainty towards a predictive strategy. It could prove challenging to develop a set of history matching models that preserve geological realism. A new Bayesian evidential learning (BEL) protocol for uncertainty quantification was released through literature, as an alternative to the model-space inversion in the history-matching approach. Consequently, an ensemble of previous geological models was developed using a prior distribution’s Monte Carlo simulation, followed by direct forecasting (DF) for joint uncertainty quantification. The goal of this work is to use prior models to identify a statistical relationship between data prediction, ensemble models, and data variables, without any explicit model inversion. The paper also introduces a new DF implementation using an ensemble smoother and shows that the new implementation can make the computation more robust than the standard method. The Utsira saline aquifer west of Norway is used to exemplify BEL’s ability to predict the CO2 mass and leakages and improve decision support regarding CO2 storage projects.

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

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