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.

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.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

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.

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.

scholarly journals Potential for CO2 Mineral Carbonation in the Paleogene Segamat Basalt of Malaysia

Minerals ◽  
2020 ◽  
Vol 10 (12) ◽  
pp. 1045
Author(s):  
Syifa Afiza Ayub ◽  
Haylay Tsegab ◽  
Omeid Rahmani ◽  
Amin Beiranvand Pour
Keyword(s):  
Co2 Storage ◽  
Mineral Carbonation ◽  
Geological Storage ◽  
X Ray Diffraction ◽  
X Ray ◽  
Carbonation Process ◽  
Mineralogical Characteristics ◽  
Distribution Of Elements ◽  
Carbon Dioxide Co2 ◽  
Geological Formations

Geological storage of carbon dioxide (CO2) requires the host rock to have the capacity to permanently store CO2 with minimum post-storage monitoring. Mineral carbonation in geological formations is one of the most promising approaches to CO2 storage as the captured CO2 is converted into stable carbonated minerals (e.g., calcite and magnesite). In this study, we investigated the geochemical and mineralogical characteristics of Segamat basalt in the Central Belt of Malaysia and evaluated its potential for mineral carbonation by using laboratory analyses of X–ray fluorescence (XRF), X–ray diffraction analysis (XRD) and petrographic study. The XRF results showed that Segamat basalt samples contain a number of elements such as Fe (21.81–23.80 wt.%), Ca (15.40–20.83 wt.%), and Mg (3.43–5.36 wt.%) that can react with CO2 to form stable carbonated minerals. The XRD and petrographic results indicated that Segamat basalt contains the reactive mineral groups of pyroxene and olivine, which are suitable for the mineral carbonation process. The results of this study could help to identify the spatial distribution of elements and minerals in the Segamat basalt and to assess its mineral carbonation potential for geological storage in Malaysia.

Using Polymer Alternating Gas to Maximize CO2 Flooding Performance

2014 ◽  
Author(s):  
W.. Li ◽  
D. S. Schechter
Keyword(s):  
Oil Recovery ◽  
Polymer Flooding ◽  
Combination Method ◽  
New Combination ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Sweep Efficiency ◽  
The North ◽  
Carbon Dioxide Co2 ◽  
Wag Injection

Abstract Carbon dioxide (CO2) has been used commercially to recover oil from reservoirs by enhanced oil recovery (EOR) technologies for over 40 years. Currently, CO2 flooding is the second most applied EOR processes in the world behind steamflooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. The average improved recovery is about 9.7%, with a range of 6 to 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is typically a challenge to reach higher oil recovery and better apply the technology. This paper proposes a new combination method called polymer alternating gas (PAG) to improve the volumetric sweep efficiency of the WAG process. The feature of this new method is that polymers are added to water during the WAG process to improve mobility ratio. In the PAG process, polymer flooding and immiscible/miscible CO2 injection are combined. To analyze the feasibility of PAG, models considering both miscible and polymer flooding processes are built to study the performance of PAG. In this paper, the sensitivity of polymer adsorption and concentration are studied. The feasibility of PAG in reservoirs with different permeabilities, different Dykstra-Parsons permeability variation coefficients (VDPs), and different fluids are also studied. A reservoir model from a typical section of the North Burbank Unit (NBU) is used to compare the performance between PAG, WAG, and polymer flooding. This study demonstrates that PAG can significantly improve recovery for immiscible/miscible flooding in homogeneous or heterogeneous reservoirs.

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.

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