Imaging Top of Volcanic Mounds Using Seismic Time- and Depth-Domain Data Processing

A seismic survey identified a basalt flow that could consist of cap rock of CO2 storage beneath saline aquifer sediment in the Southern Continental Shelf of Korea. To determine the precise depth of the basalt flow, specific depth-domain data processing of migration velocity analysis (MVA) was applied to the seismic survey data. The accurate depth measurement of a target structure provides crucial information when storing and stabilizing injected CO2 beneath basalt cap rock. Strong reflections of seismic amplitude at the volcanic mounds were adjusted from the time domain to the exact depth domain by the iterated velocity using MVA. The confidence of the updated velocity was verified by the horizontal alignment of seismic events sorted according to their common reflection point (CRP). The depth difference in volcanic mounds before and after MVA application ranged from 32.5 to 60 m along the vertical axis, showing the eruption shape on the strong-amplitude contour map in detail. The eruption shape of the top of volcanic mounds was verified with spatial continuity in 3D geological interpretation. The presented results provide suitable information that can be used to locate drilling sites and to prepare CO2 injection. The geological model obtained from both time- and depth-domain processing can significantly influence the calculation of the storage volume and can be useful for history matching studies.

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Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽

10.3390/en14061557 ◽

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.

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Snøhvit CO2 Storage Project: Assessment of CO2 Injection Performance Through History Matching of the Injection Well Pressure Over a 32-months Period

Energy Procedia ◽

10.1016/j.egypro.2013.06.214 ◽

2013 ◽

Vol 37 ◽

pp. 3267-3274 ◽

Cited By ~ 30

Author(s):

Ji-Quan Shi ◽

Claire Imrie ◽

Caglar Sinayuc ◽

Sevket Durucan ◽

Anna Korre ◽

...

Keyword(s):

History Matching ◽

Co2 Storage ◽

Injection Well ◽

Co2 Injection ◽

Project Assessment

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Fracture mapping using seismic amplitude variation with offset and azimuth analysis at the Weyburn CO2 storage site

Geophysics ◽

10.1190/geo2011-0075.1 ◽

2012 ◽

Vol 77 (6) ◽

pp. B295-B306 ◽

Cited By ~ 17

Author(s):

Alexander Duxbury ◽

Don White ◽

Claire Samson ◽

Stephen A. Hall ◽

James Wookey ◽

...

Keyword(s):

Cross Sections ◽

Co2 Storage ◽

Horizontal Stress ◽

Storage Site ◽

Fracture Zones ◽

Amplitude Variation ◽

Amplitude Variation With Offset ◽

Seal Integrity ◽

Cap Rock ◽

Weyburn Field

Cap rock integrity is an essential characteristic of any reservoir to be used for long-term [Formula: see text] storage. Seismic AVOA (amplitude variation with offset and azimuth) techniques have been applied to map HTI anisotropy near the cap rock of the Weyburn field in southeast Saskatchewan, Canada, with the purpose of identifying potential fracture zones that may compromise seal integrity. This analysis, supported by modeling, observes the top of the regional seal (Watrous Formation) to have low levels of HTI anisotropy, whereas the reservoir cap rock (composite Midale Evaporite and Ratcliffe Beds) contains isolated areas of high intensity anisotropy, which may be fracture-related. Properties of the fracture fill and hydraulic conductivity within the inferred fracture zones are not constrained using this technique. The predominant orientations of the observed anisotropy are parallel and normal to the direction of maximum horizontal stress (northeast–southwest) and agree closely with previous fracture studies on core samples from the reservoir. Anisotropy anomalies are observed to correlate spatially with salt dissolution structures in the cap rock and overlying horizons as interpreted from 3D seismic cross sections.

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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 ◽

10.2118/164932-pa ◽

2014 ◽

Vol 19 (06) ◽

pp. 1058-1068 ◽

Cited By ~ 9

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.

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Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

ASME 2012 6th International Conference on Energy Sustainability, Parts A and B ◽

10.1115/es2012-91006 ◽

2012 ◽

Cited By ~ 1

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.

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Robust CO2 Plume Imaging Using Joint Tomographic Inversion Of Distributed Pressure And Temperature Measurements

10.2118/206249-ms ◽

2021 ◽

Author(s):

Changqing Yao ◽

Hongquan Chen ◽

Akhil Datta-Gupta ◽

Sanjay Mawalkar ◽

Srikanta Mishra ◽

...

Keyword(s):

Carbon Sequestration ◽

History Matching ◽

Temperature Measurements ◽

Injection Well ◽

Co2 Injection ◽

Pressure Data ◽

Distributed Temperature Sensing ◽

Data Set ◽

Monitoring Well ◽

Co2 Plume

Abstract Geologic CO2 sequestration and CO2 enhanced oil recovery (EOR) have received significant attention from the scientific community as a response to climate change from greenhouse gases. Safe and efficient management of a CO2 injection site requires spatio-temporal tracking of the CO2 plume in the reservoir during geologic sequestration. The goal of this paper is to develop robust modeling and monitoring technologies for imaging and visualization of the CO2 plume using routine pressure/temperature measurements. The streamline-based technology has proven to be effective and efficient for reconciling geologic models to various types of reservoir dynamic response. In this paper, we first extend the streamline-based data integration approach to incorporate distributed temperature sensor (DTS) data using the concept of thermal tracer travel time. Then, a hierarchical workflow composed of evolutionary and streamline methods is employed to jointly history match the DTS and pressure data. Finally, CO2 saturation and streamline maps are used to visualize the CO2 plume movement during the sequestration process. The power and utility of our approach are demonstrated using both synthetic and field applications. We first validate the streamline-based DTS data inversion using a synthetic example. Next, the hierarchical workflow is applied to a carbon sequestration project in a carbonate reef reservoir within the Northern Niagaran Pinnacle Reef Trend in Michigan, USA. The monitoring data set consists of distributed temperature sensing (DTS) data acquired at the injection well and a monitoring well, flowing bottom-hole pressure data at the injection well, and time-lapse pressure measurements at several locations along the monitoring well. The history matching results indicate that the CO2 movement is mostly restricted to the intended zones of injection which is consistent with an independent warmback analysis of the temperature data. The novelty of this work is the streamline-based history matching method for the DTS data and its field application to the Department of Engergy regional carbon sequestration project in Michigan.

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Estimation of CO2 Diffusivity in Brine by Use of the Genetic Algorithm and Mixed Kernels-Based Support Vector Machine Model

Journal of Energy Resources Technology ◽

10.1115/1.4041724 ◽

2018 ◽

Vol 141 (4) ◽

Cited By ~ 4

Author(s):

Qihong Feng ◽

Ronghao Cui ◽

Sen Wang ◽

Jin Zhang ◽

Zhe Jiang

Keyword(s):

Genetic Algorithm ◽

Support Vector Machine ◽

Diffusion Coefficient ◽

Co2 Storage ◽

Co2 Injection ◽

Support Vector ◽

Hybrid Technique ◽

Machine Model ◽

Proposed Model ◽

Wide Range

Diffusion coefficient of carbon dioxide (CO2), a significant parameter describing the mass transfer process, exerts a profound influence on the safety of CO2 storage in depleted reservoirs, saline aquifers, and marine ecosystems. However, experimental determination of diffusion coefficient in CO2-brine system is time-consuming and complex because the procedure requires sophisticated laboratory equipment and reasonable interpretation methods. To facilitate the acquisition of more accurate values, an intelligent model, termed MKSVM-GA, is developed using a hybrid technique of support vector machine (SVM), mixed kernels (MK), and genetic algorithm (GA). Confirmed by the statistical evaluation indicators, our proposed model exhibits excellent performance with high accuracy and strong robustness in a wide range of temperatures (273–473.15 K), pressures (0.1–49.3 MPa), and viscosities (0.139–1.950 mPa·s). Our results show that the proposed model is more applicable than the artificial neural network (ANN) model at this sample size, which is superior to four commonly used traditional empirical correlations. The technique presented in this study can provide a fast and precise prediction of CO2 diffusivity in brine at reservoir conditions for the engineering design and the technical risk assessment during the process of CO2 injection.

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Overcoming CO2 Injector Well Design and Completion Challenges in a Carbonate Reservoir for World's First Offshore Carbon Capture Storage CCS SE Asia Project

10.2118/207784-ms ◽

2021 ◽

Author(s):

Mahesh S. Picha ◽

M. Azuan B. Abu Bakar ◽

Parimal A. Patil ◽

Faiz A. Abu Bakar ◽

Debasis P. Das ◽

...

Keyword(s):

Carbon Capture ◽

Injection Pressure ◽

Co2 Concentration ◽

Carbonate Reservoir ◽

Seismic Survey ◽

Co2 Injection ◽

Injection Wells ◽

Gas Field ◽

Accelerated Corrosion ◽

Well Design

Abstract Oil & Gas Operators are focusing on zero carbon emission to comply with government's changing rules and regulations, which play an important role in the encouragement of carbon capture initiatives. This paper aims to give insights on the world's first offshore CCS project in carbonate reservoir, where wells will be drilled to inject CO2, and store produced CO2 from contaminated fields. To safeguard the storage containment, the integrity of all wells needs to be scrutinized. Development wells in the identified depleted gas field are more than 40 years old and were not designed with consideration of high CO2 concentration in the reservoir. In consequence, the possibility of well leakage due to accelerated corrosion channeling and cracks, along the wellbore cannot be ignored and require careful evaluation. Rigorous process has been adopted in assessing the feasibility for converting existing gas producers into CO2 injectors. The required defined basis of designs for gas producer and CO2 injection wells differs in a great extent and this governs the re-usability of wells for CO2 injection or necessity to be abandoned. Three (3) new CO2 injectors with fat to slim design approach, corrosion resistant alloy (CRA) material and CO2 resistant cement are designed in view to achieve lifecycle integrity. Optimum angle of 53 deg and maintaining the injection pressure of 50 bar at 90 MSCFD rate is required for the injection of supercritical CO2 for 20 years. During well execution, challenges such as anti-collision risk, total loss scenarios while drilling in Carbonate reservoir need to be addressed before execution. The completion design is also focusing on having minimal number of completion jewelries to reduce pressure differential and potential leak paths from tubing hangar down to the end of lower completion. The selection of downhole safety valve (TRSV) type is of high importance to accommodate CO2 phase attributes at different pressure/temperature. Fiber Optic is included for monitoring the migration of CO2 plume by acquiring seismic survey and for well integrity by analyzing DAS/DTS data.

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