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Forecasting CO₂ Sequestration with Enhanced Oil Recovery II

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: 27 June 2024 | Viewed by 8513

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Dr. William Ampomah

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Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM, USA
Interests: reservoir characterization; simulation; optimization; enhanced oil recovery; CO₂ storage
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Prof. Dr. Brian McPherson

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Energy & Geoscience Institute (EGI), University of Utah, Salt Lake City, UT, USA
Interests: simulation; risk assessment; reactive transport
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Dr. Robert Balch

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Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM, USA
Interests: reservoir characterization; MVA; CO₂ storage
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Dr. Reid Grigg

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Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM, USA
Interests: numerical modeling; enhanced oil recovery; risk assessment
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Martha Cather

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Guest Editor

Petroleum Recovery Research Center, New Mexico Insitute of Mining and Technology, Socorro, NM, USA
Interests: reservoir characterization; MVA; CO₂ storage
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Special Issue Information

Dear Colleagues,

The aim of carbon capture, utilization, and storage (CCUS) is to reduce the amount of CO₂ released into the atmosphere and to mitigate its effects on climate change. Over the years, naturally occurring CO₂ sources have been utilized in enhanced oil recovery (EOR) projects in the United States. This has presented an opportunity to supplement and gradually replace the high demand for natural CO₂ sources with anthropogenic sources. There also exist incentives for operators to become involved in the storage of anthropogenic CO₂ within partially depleted reservoirs, besides the incremental produced oil revenues. These incentives include a wider availability of anthropogenic sources, the reduction of emissions to meet regulatory requirements, tax incentives in some jurisdictions, and favorable public relations.

The United States Department of Energy through its Carbon Storage program has sponsored several Regional Carbon Sequestration Partnerships (RCSPs) that have conducted field demonstrations for both EOR and saline aquifer storage. Various research efforts have been made in the area of reservoir characterization, monitoring, verification and accounting, simulation, and risk assessment to ascertain long-term storage potential within the subject storage complex. This Special Issue is a collection of lessons learned through the RCSP program within the Southwest Region of the United States. This Special Issue invites scientific output from the RSCP program on the following topics related to CCUS:

Reservoir characterization for CCUS;
Monitoring, verification, and accounting;
Advanced numerical simulation of CO₂-EOR and storage;
Risk Assessment of long-term CO₂ storage.

Any article submitted by a Guest Editor will be handled by a member of the Editorial Board to avoid any conflicts of interest.

Dr. William Ampomah
Prof. Dr. Brian McPherson
Dr. Robert Balch
Dr. Reid Grigg
Martha Cather
Guest Editors

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Keywords

reservoir characterization
enhanced oil recovery
CO₂ storage
co-optimization
numerical simulation reactive transport
uncertainty quantification
CO₂ monitoring
time-lapse analysis

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Forecasting CO₂ Sequestration with Enhanced Oil Recovery in Energies (14 articles)

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Research

47 pages, 10495 KiB

Open AccessArticle

Mechanisms of Waterflood Inefficiency: Analysis of Geological, Petrophysical and Reservoir History, a Field Case Study of FWU (East Section)

by Anthony Morgan, William Ampomah, Reid Grigg, Sai Wang and Robert Czarnota

Energies 2024, 17(7), 1565; https://doi.org/10.3390/en17071565 - 25 Mar 2024

Viewed by 438

Abstract

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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27 pages, 36684 KiB

Open AccessArticle

Control of Cement Timing, Mineralogy, and Texture on Hydro-chemo-mechanical Coupling from CO₂ Injection into Sandstone: A Synthesis

by Zhidi Wu, Jason D. Simmons, Samuel Otu, Alex Rinehart, Andrew Luhmann, Jason Heath, Peter Mozley and Bhaskar S. Majumdar

Energies 2023, 16(24), 7949; https://doi.org/10.3390/en16247949 - 07 Dec 2023

Viewed by 802

Abstract

Carbon capture, utilization, and storage (CCUS) has been widely applied to enhance oil recovery (CO₂-EOR). A thorough investigation of the impact of injecting CO₂ into a heterogeneous reservoir is critical to understanding the overall reservoir robustness and storage performance. We conducted fifteen flow-through tests on Morrow B sandstone that allowed for chemical reactions between a CO₂-rich brackish solution and the sandstones, and four creep/flow-through tests that simultaneously allowed for chemical reactions and stress monitoring. From fluid chemistry and X-ray computed tomography, we found that the dissolution of disseminated cements and the precipitation of iron-rich clays did not significantly affect the permeability and geomechanical properties. Minor changes in mechanical properties from Brazilian and creep tests indicated that the matrix structure was well-supported by early diagenetic quartz overgrowth cement and the reservoir’s compaction history at deep burial depths. However, one sample experienced a dissolution of poikilotopic calcite, leading to a permeability increase and significant tensile strength degradation due to pore opening, which overcame the effect of the early diagenetic cements. We concluded that the Morrow B sandstone reservoir is robust for CO₂ injection. Most importantly, cement timing, the abundance and texture of reactive minerals, and the reservoir’s burial history are critical in predicting reservoir robustness and storage capacity for CO₂ injection. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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19 pages, 5226 KiB

Open AccessEditor’s ChoiceArticle

Multi-Scale Seismic Measurements for Site Characterization and CO₂ Monitoring in an Enhanced Oil Recovery/Carbon Capture, Utilization, and Sequestration Project, Farnsworth Field, Texas

by George El-kaseeh and Kevin L. McCormack

Energies 2023, 16(20), 7159; https://doi.org/10.3390/en16207159 - 19 Oct 2023

Viewed by 781

Abstract

To address the challenges of climate change, significantly more geologic carbon sequestration projects are beginning. The characterization of the subsurface and the migration of the plume of supercritical carbon dioxide are two elements of carbon sequestration that can be addressed through the use of the available seismic methods in the oil and gas industry. In an enhanced oil recovery site in Farnsworth, TX, we employed three separate seismic techniques. The three-dimensional (3D) surface seismic survey required significant planning, design, and processing, but produces both a better understanding of the subsurface structure and a three-dimensional velocity model, which is essential for the second technique, a timelapse vertical seismic profile, and the third technique, cross-well seismic tomography. The timelapse 3D Vertical Seismic Profile (3D VSP) revealed both significant changes in the reservoir between the second and third surveys and geo-bodies that may represent the extent of the underground carbon dioxide. The asymmetry of the primary geo-body may indicate the preferential migration of the carbon dioxide. The third technique, cross-well seismic tomography, suggested a strong correlation between the well logs and the tomographic velocities, but did not observe changes in the injection interval. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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32 pages, 12686 KiB

Open AccessArticle

Probabilistic Evaluation of Geomechanical Risks in CO₂ Storage: An Exploration of Caprock Integrity Metrics Using a Multilaminate Model

by Si-Yong Lee, Farid Reza Mohamed, Kwang-Ho Lee, Brian McPherson, Robert Balch and Sangcheol Yoon

Energies 2023, 16(19), 6954; https://doi.org/10.3390/en16196954 - 05 Oct 2023

Viewed by 918

Abstract

The probabilistic uncertainty assessment of geomechanical risk—specifically, caprock failure—attributable to CO₂ injection, as presented in a simplified hypothetical geological model, was the focus of this study. Our approach amalgamates the implementation of a multilaminate model, the creation of a response surface model in conjunction with the Box–Behnken sampling design, the execution of associated numerical modeling experiments, and the utilization of Monte Carlo simulations. Probability distributions to encapsulate the inherent variability (elastic and mechanical properties of the caprock and reservoir) and uncertainty in prediction estimates (vertical displacement, total strain, and F value) were employed. Our findings reveal that the Young modulus of the caprock is a key factor controlling equivalent total strain but is insufficient as a stand-alone indicator of caprock integrity. It is confirmed that the caprock can accommodate significant deformation without failure, if it possesses a low Young’s modulus and high mechanical strength properties, such as the friction angle and uniaxial compressive strength. Similarly, vertical displacement was found to be an unreliable indicator for caprock integrity, as caprock failure can occur across a broad spectrum of vertical displacements, particularly when both the Young modulus and mechanical strength properties have wide ranges. This study introduces the F value as the most dependable indicator for caprock failure, although it is a theoretical attribute (the shortest distance between the Mohr circle and the nearest failure envelope used to measure the sensitivity to failure) and not physically measurable in the field. Deviatoric stress levels were found to vary based on stress regimes, with the maximum levels observed under extensive and compressive stress regimes. In conjunction with the use of the response surface method, this study demonstrates the efficacy of the multilaminate framework and the Mohr–Coulomb constitutive model in providing a simplified, yet effective, probabilistic model of the mechanical behavior of caprock failure, reducing mathematical and computational complexities. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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26 pages, 5862 KiB

Open AccessArticle

Legacy Well Leakage Risk Analysis at the Farnsworth Unit Site

by Shaoping Chu, Hari Viswanathan and Nathan Moodie

Energies 2023, 16(18), 6437; https://doi.org/10.3390/en16186437 - 06 Sep 2023

Cited by 1 | Viewed by 767

Abstract

This paper summarizes the results of the risk analysis and characterization of the CO₂ and brine leakage potential of Farnsworth Unit (FWU) site wells. The study is part of the U.S. DOE’s National Risk Assessment Partnership (NRAP) program, which aims to quantitatively evaluate long-term environmental risks under conditions of significant geologic uncertainty and variability. To achieve this, NRAP utilizes risk assessment and computational tools specifically designed to quantify uncertainties and calculate the risk associated with geologic carbon dioxide (CO₂) sequestration. For this study, we have developed a workflow that utilizes physics-based reservoir simulation results as input to perform leakage calculations using NRAP Tools, specifically NRAP-IAM-CS and RROM-Gen. These tools enable us to conduct leakage risk analysis based on ECLIPSE reservoir simulation results and to characterize wellbore leakage at the Farnsworth Unit Site. We analyze the risk of leakage from both individual wells and the entire field under various wellbore integrity distribution scenarios. The results of the risk analysis for the leakage potential of FWU wells indicate that, when compared to the total amount of CO₂ injected, the highest cemented well integrity distribution scenario (FutureGen high flow rate) exhibits approximately 0.01% cumulative CO₂ leakage for a 25-year CO₂ injection duration at the end of a 50-year post-injection monitoring period. In contrast, the highest possible leakage scenario (open well) shows approximately 0.1% cumulative CO₂ leakage over the same time frame. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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22 pages, 10318 KiB

Open AccessFeature PaperArticle

Investigation of the Effect of Injected CO₂ on the Morrow B Sandstone through Laboratory Batch Reaction Experiments: Implications for CO₂ Sequestration in the Farnsworth Unit, Northern Texas, USA

by Eusebius J. Kutsienyo, Martin S. Appold and Martha E. Cather

Energies 2023, 16(12), 4611; https://doi.org/10.3390/en16124611 - 09 Jun 2023

Viewed by 776

Abstract

About one million tons of CO₂ have been injected into the Farnsworth unit to date. The target reservoir for CO₂ injection is the Morrow B Sandstone, which is primarily made of quartz with lesser amounts of albite, calcite, chlorite, and clay minerals. The impact of CO₂ injection on the mineralogy, porosity, and pore water composition of the Morrow B Sandstone is a major concern. Although numerical modeling studies suggest that porosity changes will be minimal, significant alterations to mineralogy and pore water composition are expected. Given the implications for CO₂ storage effectiveness and risk assessment, it is crucial to verify the accuracy of theoretical model predictions through laboratory experiments. To this end, batch reaction experiments were conducted to model conditions near an injection well in the Morrow B Sandstone and at locations further away, where the CO₂ has been diluted by formation water. The laboratory experiments involved submerging thin sections of both coarse- and fine-grained facies of the Morrow B Sandstone in formation water samples with varying levels of CO₂. The experiments were conducted at the reservoir temperature of 75 °C. Two experimental runs were conducted, one lasting for 61 days and the other for 72 days. The initial fluid composition used in the second run was the same as in the first. The mineralogy changes in the thin sections were analyzed using SEM and the Tescan Integrated Mineral Analyzer (TIMA), while changes in the composition of the formation water were determined using ICP-AES. During each experiment, a thin layer of white fine-grained particles consisting mainly of dolomite and silica formed on the surface of the thin sections, leading to significant reductions in Ca, Mg, and Sr in the formation water. This outcome is consistent with numerical model predictions that dolomite would be the primary mineral that would react with injected CO₂ and that silica would be oversaturated in the formation water. Changes in mineral abundance in the thin sections themselves were much less systematic than in the theoretical modeling experiments, perhaps reflecting heterogeneities in the mineral grain size surface area to volume ratios and mineral distributions in the thin sections not considered in the numerical models. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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14 pages, 12273 KiB

Open AccessArticle

Microseismic Monitoring at the Farnsworth CO₂-EOR Field

by Yan Qin, Jiaxuan Li, Lianjie Huang, Kai Gao, David Li, Ting Chen, Tom Bratton, George El-kaseeh, William Ampomah, Titus Ispirescu, Martha Cather, Robert Balch, Yingcai Zheng, Shuhang Tang, Kevin L. McCormack and Brian McPherson

Energies 2023, 16(10), 4177; https://doi.org/10.3390/en16104177 - 18 May 2023

Cited by 2 | Viewed by 1206

Abstract

The Farnsworth Unit in northern Texas is a field site for studying geologic carbon storage during enhanced oil recovery (EOR) using CO

_{2}

. Microseismic monitoring is essential for risk assessment by detecting fluid leakage and fractures. We analyzed borehole microseismic data acquired [...] Read more.

The Farnsworth Unit in northern Texas is a field site for studying geologic carbon storage during enhanced oil recovery (EOR) using CO

_{2}

. Microseismic monitoring is essential for risk assessment by detecting fluid leakage and fractures. We analyzed borehole microseismic data acquired during CO

_{2}

injection and migration, including data denoising, event detection, event location, magnitude estimation, moment tensor inversion, and stress field inversion. We detected and located two shallow clusters, which occurred during increasing injection pressure. The two shallow clusters were also featured by large b values and tensile cracking moment tensors that are obtained based on a newly developed moment tensor inversion method using single-borehole data. The inverted stress fields at the two clusters showed large deviations from the regional stress field. The results provide evidence for microseismic responses to CO

_{2}

/fluid injection and migration. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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24 pages, 7910 KiB

Open AccessArticle

Coupled Hydromechanical Modeling and Assessment of Induced Seismicity at FWU: Utilizing Time-Lapse VSP and Microseismic Data

by Samuel Appiah Acheampong, William Ampomah, Don Lee and Angus Eastwood-Anaba

Energies 2023, 16(10), 4163; https://doi.org/10.3390/en16104163 - 18 May 2023

Cited by 2 | Viewed by 886

Abstract

The objective of this work is to utilize integrated geomechanics, field vertical seismic profile (VSP) and microseismic data to characterize the complex subsurface stress conditions at the Farnsworth Unit (FWU). The model is based on a five-spot sector model extracted from a primary geomechanical model. The five-spot well injection pattern is characterized by extensive reservoir characterization data, such well logs, extracted cores and borehole geophone data, to facilitate the detailed examination of stress changes and microseismic event occurrences. The study utilizes field vertical seismic volumes acquired from the injection well 13-10A. The seismic volumes successfully provided snapshots of the behavior of the reservoir at distinct times. The use of VSP and microseismic data provided direct and indirect estimates of the dynamic stress changes occurring in the overburden, reservoir and underburden rock formations. In order to illuminate the stress regions and identify rocks that have undergone inelastic failure, microseismic event occurrences were utilized. Microseismic activity has been detected at the FWU; further study of its locations, timing, and magnitude was needed to deduce the nature of the changing stress state. The results of the study revealed that microseismic events were successfully modeled within the Morrow B formation. Moment magnitudes of seismic events were within the same magnitudes for events in the reservoir, suggesting the suitability of the model. The results of the study showed that the computed moment magnitudes for seismic events were insignificant to warrant safety concerns. The study findings showed the usefulness of coupled hydromechanical models in predicting the subsurface stress changes associated with CO₂ injection. The knowledge gained from this study will serve as a guideline for industries planning to undertake underground CO₂ storage, and characterize the subsurface stress changes. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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19 pages, 15068 KiB

Open AccessArticle

Seismic Monitoring at the Farnsworth CO₂-EOR Field Using Time-Lapse Elastic-Waveform Inversion of 3D-3C VSP Data

by Xuejian Liu, Lianjie Huang, Kai Gao, Tom Bratton, George El-Kaseeh, William Ampomah, Robert Will, Paige Czoski, Martha Cather, Robert Balch and Brian McPherson

Energies 2023, 16(9), 3939; https://doi.org/10.3390/en16093939 - 06 May 2023

Cited by 1 | Viewed by 1351

Abstract

During the Development Phase of the U.S. Southwest Regional Partnership on Carbon Sequestration, supercritical CO₂ was continuously injected into the deep oil-bearing Morrow B formation of the Farnsworth Unit in Texas for Enhanced Oil Recovery (EOR). The project injected approximately 94 kilotons of CO₂ to study geologic carbon storage during CO₂-EOR. A three-dimensional (3D) surface seismic dataset was acquired in 2013 to characterize the subsurface structures of the Farnsworth site. Following this data acquisition, the baseline and three time-lapse three-dimensional three-component (3D-3C) vertical seismic profiling (VSP) data were acquired at a narrower surface area surrounding the CO₂ injection and oil/gas production wells between 2014 and 2017 for monitoring CO₂ injection and migration. With these VSP datasets, we inverted for subsurface velocity models to quantitatively monitor the CO₂ plume within the Morrow B formation. We first built 1D initial P-wave (V_p) and S-wave (V_s) velocity models by upscaling the sonic logs. We improved the deep region of the V_p and V_s models by incorporating the deep part of a migration velocity model derived from the 3D surface seismic data. We improved the shallow region of 3D V_p and V_s models using 3D traveltime tomography of first arrivals of VSP downgoing waves. We further improved the 3D baseline velocity models using elastic-waveform inversion (EWI) of the 3D baseline VSP upgoing data. Our advanced EWI method employs alternative tomographic and conventional gradients and total-variation-based regularization to ensure the high-fidelity updates of the 3D baseline V_p and V_s models. We then sequentially applied our 3D EWI method to the three time-lapse datasets to invert for spatiotemporal changes of V_p and V_s in the reservoir. Our inversion results reveal the volumetric changes of the time-lapse V_p and V_s models and show the evolution of the CO₂ plume from the CO₂ injection well to the oil/gas production wells. Full article

(This article belongs to the Special Issue Forecasting CO₂ Sequestration with Enhanced Oil Recovery II)

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Forecasting CO₂ Sequestration with Enhanced Oil Recovery II