Analysis of Microseismicity and Reactivated Fault Size to Assess the Potential for Felt Events by CO2 Injection in the Illinois Basin

ABSTRACT The results of monitoring of carbon dioxide (CO2) injection at the Illinois Basin—Decatur Project (IBDP) and the companion Illinois Industrial Carbon Capture and Sequestration Sources (IL-ICCS) project—have shown that reservoir response to fluid pressure changes can vary significantly at different injection locations within the same reservoir. Predrill reservoir characterization is important to identify potentially seismogenic faults. However, interpretations of newly reprocessed 3D seismic reflection data illustrate the challenges related to their identification in a region dominated by faulting with small vertical offsets. Faults interpreted in the 3D seismic volume range from ∼300 to 1200 m wide and are in the same size range as faults that could have been the source of historical events up to Mw 2.7 in central Illinois. The array of monitoring sensors that was installed for the IBDP continues to collect data, as injection operates in IL-ICCS, the second injection well. CO2 injection rates for the IL-ICCS well are on average 1.7 times the rates injected in the IBDP well, but a significantly reduced rate of induced seismicity is observed. This article presents results of passive seismic monitoring for the duration of the project to date, integrating active and passive seismic data to develop a new interpretation of the subsurface structure at the Decatur site that explicitly identifies pathways for fluid flow into the basement leading to induced seismicity, and provides a geological explanation for the sharp reduction of induced seismicity during injection at higher rates into the second well. The use of seismic moment to estimate the length of seismogenic slip planes in the local subsurface suggests that faults large enough to produce felt seismicity are unlikely to be present at or near the Decatur site.

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Investigating fault continuity associated with geologic carbon storage planning in the Illinois Basin

Interpretation ◽

10.1190/int-2013-0109.1 ◽

2014 ◽

Vol 2 (1) ◽

pp. SA151-SA162 ◽

Cited By ~ 3

Author(s):

John H. McBride ◽

R. William Keach ◽

Eugene E. Wolfe ◽

Hannes E. Leetaru ◽

Clayton K. Chandler ◽

...

Keyword(s):

Carbon Storage ◽

Seismic Reflection ◽

Oil Field ◽

Illinois Basin ◽

Storage Site ◽

3D Seismic ◽

Seismic Attribute ◽

Seismic Reflection Data ◽

Reflection Data ◽

Attribute Analyses

Because the confinement of [Formula: see text] in a storage reservoir depends on a stratigraphically continuous set of seals to isolate the fluid in the reservoir, the detection of structural anomalies is critical for guiding any assessment of a potential subsurface carbon storage site. Employing a suite of 3D seismic attribute analyses (as opposed to relying upon a single attribute) maximizes the chances of identifying geologic anomalies or discontinuities (e.g., faults) that may affect the integrity of a seal that will confine the stored [Formula: see text] in the reservoir. The Illinois Basin, a major area for potential carbon storage, presents challenges for target assessment because geologic anomalies can be ambiguous and easily misinterpreted when using 2D seismic reflection data, or even 3D data, if only conventional display techniques are used. We procured a small 3D seismic reflection data set in the central part of the basin (Stewardson oil field) to experiment with different strategies for enhancing the appearance of discontinuities by integrating 3D seismic attribute analyses with conventional visualizations. Focusing on zones above and below the target interval of the Cambrian Mt. Simon Sandstone, we computed attribute traveltime slices (combined with vertical views) based on discontinuity computations, crossline-directed amplitude change, azimuth of the dip, shaded relief, and fault likelihood attributes. The results provided instructive examples of how discontinuities (e.g., subseismic scale faults) may be almost “invisible” on conventional displays but become detectable and mappable using an appropriate integration of 3D attributes. Strong discontinuities in underlying Precambrian basement rocks do not necessarily propagate upward into the target carbon storage interval. The origin of these discontinuities is uncertain, but we explored a possible strike-slip role that also explains the localization of a structural embayment developed in Lower Paleozoic strata above the basement discontinuities.

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Coupled Hydromechanical Modeling of Induced Seismicity from CO2 Injection in the Illinois Basin

10.1002/essoar.10508521.1 ◽

2021 ◽

Author(s):

Keurfon Luu ◽

Martin Schoenball ◽

Curtis Martin Oldenburg ◽

Jonny Rutqvist

Keyword(s):

Induced Seismicity ◽

Co2 Injection ◽

Illinois Basin

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Amangi field reservoir porosity and saturation estimation using seismic and well data

Scientia Africana ◽

10.4314/sa.v20i1.14 ◽

2021 ◽

Vol 20 (1) ◽

pp. 159-170

Author(s):

S. Inichinbia ◽

G.O. Emujakporue

Keyword(s):

Reservoir Characterization ◽

Acoustic Properties ◽

Well Log ◽

3D Seismic ◽

Seismic Reflection Data ◽

Reflection Data ◽

Production Wells ◽

Areal Sampling ◽

Seismic Amplitudes ◽

Lateral Variations

The scientific knowledge of mapping reservoir geometries provide useful displays for understanding the sediment fairway orientation and transport direction, they are not detailed enough to define the best quality well connected reservoir areas needed for planningdevelopment wells. Knowing that that long term development of this field will require excellent subsurface imaging to optimize the placement of future development and production wells, so to plan for this, we used strong reflected primaries (PP) and primary-shear (PS) waves imaging for the reservoir characterization. Porosity of two hydrocarbon reservoirs is investigated for the purpose of planning production operations in Amangi field of the Nigerian Delta. Well log derived porosities were measured at five appraisal wells in the field. Point information about the porosity of the reservoirs were determined from these well log data. However, lateral variations of porosity could not be delineated from measurements made only at the sparsely located wells in the field. A 3D seismic data covering an area of about 20 km x 17.5 km were acquired to delineate the extent of the porous sand. After careful data processing, the lateral variations of seismic amplitudes were transformed to changes in rock impedances, which, in turn, are indirectly related to porosity. In contrast with the sparse well observations, the 3D seismic method provided a dense and regular areal sampling of the acoustic properties of the reservoir intervals. The results of the transformation of the 3D anisotropic seismic reflection data were integrated with petrophysical measurements at the wells to significantly improve the spatial description of porosity in this field.

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Reservoir Characterization and Storage Capacity Evaluation for Carbon Capture and Storage: A Case Study From East Natuna

Proc of Indonesian Petroleum Association 42nd Annual Convention ◽

10.29118/ipa19.g.204 ◽

2018 ◽

Author(s):

K. Prabowo

Keyword(s):

Carbon Capture ◽

Reservoir Characterization ◽

Storage Capacity ◽

Carbon Capture And Storage ◽

Capacity Evaluation ◽

And Storage

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Reservoir Characterization using a Merged and Reprocessed 3D Seismic to Open Up New Opportunity between Existing Field in Barito Basin Indonesia

Proc of Indonesian Petroleum Association 42nd Annual Convention ◽

10.29118/ipa19.g.414 ◽

2018 ◽

Author(s):

A. Nurhasan

Keyword(s):

Reservoir Characterization ◽

3D Seismic

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Antelope shale (Monterey Formation), Buena Vista Hills field: Advanced reservoir characterization to evaluate CO2 injection for enhanced oil recovery

AAPG Bulletin ◽

10.1306/8626c947-173b-11d7-8645000102c1865d ◽

2001 ◽

Vol 85 ◽

Author(s):

Scott L. Montgomery,1 Michael F. Mo

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Reservoir Characterization ◽

Co2 Injection ◽

Monterey Formation ◽

Buena Vista

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

SPE Journal ◽

10.2118/205503-pa ◽

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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Geomechanical aspects of induced microseismicity during CO2 injection in Illinois Basin

The Leading Edge ◽

10.1190/tle40110823.1 ◽

2021 ◽

Vol 40 (11) ◽

pp. 823-830

Author(s):

Nikita Bondarenko ◽

Sherilyn Williams-Stroud ◽

Jared Freiburg ◽

Roman Makhnenko

Keyword(s):

Oil Field ◽

Co2 Injection ◽

Low Permeability ◽

Illinois Basin ◽

Petrographic Analysis ◽

Flow Properties ◽

Geomechanical Characterization ◽

Fluid Penetration ◽

Geophysical Log

Carbon sequestration activities are increasing in a global effort to mitigate the effects of greenhouse gas emissions on the climate. Injection of wastewater and oil-field fluids is known to induce seismic activity. This makes it important to understand how that risk relates to CO2 injection. Injection of supercritical CO2 into the Cambrian Mt. Simon sandstone in Illinois Basin induced microseismicity that was observed below the reservoir, primarily in the Precambrian crystalline basement. Geomechanical and flow properties of rock samples from the involved formations were measured in the laboratory and compared with geophysical log data and petrographic analysis. The controlling factors for induced microseismicity in the basement seem to be the hydraulic connection between the reservoir and basement rock and reactivation of pre-existing faults or fractures in the basement. Additionally, the presence of a laterally continuous low-permeability layer between reservoir and basement may have prevented downward migration of pore pressure and reactivation of critically stressed planes of weakness in the basement. Results of the geomechanical characterization of this intermediate layer indicate that it may act as an effective barrier for fluid penetration into the basement and that induced microseismicity is likely to be controlled by the pre-existing system of faults. This is because the intact material is not expected to fail under the reservoir stress conditions.

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