Integrated Analysis of Geomechanical Factors for Geologic CO2 Storage in the Midwestern United States

Available online at www.sciencedirect.com

ScienceDirect Energy Procedia 114 (2017) 3267 – 3272

13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Integrated Analysis of Geomechanical Factors for Geologic CO2 Storage in the Midwestern United States J.R. Sminchak1, Ola Babarinde2, and Neeraj Gupta1 1 Battelle, Columbus, OH, USA Illinois Geological Survey, Champaign, Illinois

2

Abstract

Many deep saline rock formations have the capacity for large-scale CO2 storage in the Midwestern United States. However, geomechanical factors are not well characterized throughout the region. In this project, subsurface geomechanical conditions were described based on geologic structures, geomechanical core tests, geophysical log analysis, fracture breakdown pressure data from oil and gas wells, and the spatial arrangement of deep saline rock formations suitable for CO2 storage. The research focused on portraying regional variations of these factors, fracture patterns in key intervals, and their impact on design and operation of CO 2 injection wells and the storage process. © Published by by Elsevier Ltd.Ltd. This is an open access article under the CC BY-NC-ND license ©2017 2017The TheAuthors. Authors. Published Elsevier (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2 storage, geomechanics; fractures; characterization; stress

1.

Introduction

Large-scale CO2 injection in the subsurface has the potential to cause stress changes in both the target reservoirs and surrounding formations (Rutquist, 2012; Sminchak et al., 2003; Lucier et al., 2006). A geomechanical assessment of formation integrity may be used to better understand stress alteration during CO2 injection and determine whether the stress state compromises the ability of reservoirs to store CO 2 safely and effectively. Consequently, the geomechanical properties of reservoirs and confining layers need to be characterized in order to investigate safe, cost-effective CO2 storage. Collecting the information needed to formally determine the geomechanical characteristics of the reservoirs and

1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1458

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confining layers may be technically difficult and expensive. As a result, the lack of information on geomechanical conditions introduces uncertainties to the evaluation of stress field changes and the potential for geomechanical deformation. In addition, areas in the Midwest United States have many formations, including reservoirs and caprocks, which are considered to be fractured (Milici, 1980; Roen and Walker, 1996). These fractures can exhibit various types, sizes, orientation, and arrangement, all of which can affect the pathway of fluid flow in the underground fractured rock mass. A comprehensive description of the fracture density within these rocks provides a foundation to evaluate CO2 storage feasibility in the region. The ability to determine the amount of feasible pressure increase at a site is an important research need because this pressure increase is a key factor for safe operations, the number of injection wells, and storage field size. Changes in mechanical stress and subsurface deformation fields in and around the injection reservoirs can induce seismicity and microseismicity, generate new fractures, and/or activate pre-existing fractures to provide a pathway for CO2 migration. CO2 injection into reservoirs creates anomalously high pore pressure at the top of the reservoir, which could hydraulically fracture the caprock or trigger slip on reservoir-bounding faults by reducing effective normal stress on the fault surface (Chiaramonte, 2009). A safe injection pressure is one that falls below the least compressive principal stress of the reservoir to avoid hydraulic fracturing. The amount of pressure increase feasible at a site is also a regulated operational parameter. If the amount of pressure increase considered to be safe for injection is low due to low fracture pressure, this could significantly affect the total CO2 storage capacity in the reservoirs. This study was focused on the Midwestern United States, where many large industrial carbon sources and suitable geologic sinks are located (Figure 1). In this region, Paleozoic age sedimentary rock formations form broad basins and arches that reflect long periods of diagenesis and multiple orogenic events, which has resulted in the development of a complex fracture system within some of the carbonate and clastic units. Throughout much of this region, the deeper Ordovician-Cambrian age rocks are targets for CO2 storage because they have suitable depth/temperature for supercritical phase CO2 storage, thick caprocks, and reasonable reservoir intervals (Greb et al., 2012; Barnes, 2009). Understanding the orientation and distribution of the natural fracture sets and stress conditions within the rock layers is necessary to prevent geomechanical deformation in the subsurface due to large-scale CO2 storage projects.

Figure 1. Midwest U.S. Stress Regime Conceptual Diagram.

2.

Methods

Geomechanical rock core test data from 20 wells across the region were compiled and described with statistics, maps, and graphs. The objective of the analysis was to develop population distributions of these parameters, rather than single well data points. While geomechanical rock core tests are not frequently performed, the data provide valuable calibration points for geophysical log analysis. For the various Devonian to Cambrian age rocks tested, results showed bulk density range of 2.24-2.83 g/cc, static Young’s Modulus range of 13-79 GPa, and static Poisson’s Ratio range of 0.15-0.41 (Table 1). In general, the values reflect the older, well lithified nature of the rocks in Paleozoic age basins and arches structures. Most parameters showed a fairly normal distribution. There were some trends related to lithology, indicating geomechanical integrity may be related to mineralogy and pore structure of rocks.

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Table 1. Rock Core Test Geomechanical Parameters for Deeper Rock Units in the Midwestern United States. Dynamic Static Confining Bulk Comp. Shear Dynamic Bulk Shear Comp. Static Young's Young's Parameter Pressure Density Velocity Velocity Poisson's Modulus Modulus Strength Poisson's Modulus Modulus (MPa) (g/cc) (m/s) (m/s) Ratio (GPa) (GPa) (MPa) Ratio (GPa) (GPa)

Count

50

50

39

39

Minimum

3.2

2.24

3810

Maximum

21.8

2.83

6897

Range

18.6

0.59

Median

11.4

Mean

11.4 4.2

Std. Dev.

39

39

39

39

44

44

44

2327

30.6

0.085

15.0

13.2

105

12.9

0.15

4023

111.8

0.35

78.5

45.0

615

78.9

0.42

3087

1696

81.2

0.27

63.6

31.8

511

66.0

0.27

2.6

5210

2916

60.5

0.26

39.6

23.7

207

39.8

0.26

2.6

5274

2984

59.9

0.25

43.8

23.9

228

43.0

0.26

0.15

790

360

17.2

0.07

18.6

6.6

107

17.9

0.07

Geophysical log analysis included processing and interpretation of 13 borehole image logs across the region. The logs were analysed in order to categorize wellbore breakouts, drilling induced fractures, and natural fractures. More than 700 observations of pre-existing natural fractures were interpreted on newly acquired electrical image logs collected at multiple well locations ranging in depth from 730 to 4150 meters. Data were analysed by formation to determine stress orientation and frequency of natural fractures. Results of the log analysis and interpretation suggests the regional fracture systems are highly complex with possibly systematic and non-systematic fractures present within the evaluated lithologic units. Fracture density was observed to increase up-dip within the studied area where regional structural arches are present (Figure 2). A high percentage of fractures with varying dip direction were observed to strike sub-parallel to the contemporary maximum horizontal stress direction (SHmax) determined from well bore failure, while a lower percentage strikes perpendicular to the SHmax direction. Critically-stressed fracture analysis shows the natural fractures are not critically stressed in the current state. Log analysis suggests that stress orientation generally follows the predominant N 60 E principal stress orientation seen in this region.

Figure 2. Analysis of fracture density from image logs in Cambrian-Ordovician rock layers in Midwest U.S.

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One limitation of geomechanical analysis is determining the in-situ stress magnitude in deep rock formations. There are very few well tests or mini-fracture tests performed in wells due to expense and field time necessary to complete these tests. However, well completion/treatment measurements from oil and gas wells on fracture breakdown pressures and shut-in pressures can help to better constrain stress magnitudes. A database of more than 20,000 fracture breakdown pressure data was compiled for rock formations in the Midwest U.S. The breakdown data were used to depict in-situ stress magnitude of different rock formations (Baree and Miskimins, 2015; Hawkes et al., 2005; Gronesth and Kry, 1983; McLelland, 1988). While there are limitations to the nature of breakdown pressures from well completions, there is a large amount of data, which helps depicts trends in stress magnitudes in the region. This information was combined with geophysical log methods to derive stress magnitude to better understand stress state of deep rock formations being considered for CO 2 storage in the region. Figure 3 illustrates estimated instantaneous shut-in pressures by formation and depth. As shown, the shut-in pressures show a large amount of variability, which may be related to well treatment procedures, materials, and many other factors. Most instantaneous shut-in pressure gradients ranged from 0.7-1.0 psi/ft (16-23 kPa/m). Data from horizontal Utica-Point Pleasant shale gas wells showed a higher shut-in pressure gradient, possibly related to hoop stress and other processes related to completion methods in long horizontal wells. In addition, there was a trend of increasing modulus toward the Appalachian structural front.

Figure 3. Instantaneous shut-in pressure data by formation and depth.

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3.

Results and Conclusions

Analysis of subsurface geomechanical conditions was completed based on geologic structures, geomechanical core tests, geophysical log analysis, fracture breakdown pressure data from oil and gas wells, and the spatial arrangement of deep saline rock formations suitable for CO2 storage. Core test data provide fundamental information on the physical properties of the deep rock layers. Overall, the test data reflect the dense, well-lithified nature of the deeper Ordovician-Cambrian rock formations, with average static Young’s Modulus of 40 GPa. Analysis of regional geophysical image logs provides a better understanding of stress orientation and density of natural fractures. The maximum horizontal stress orientation of predominately N60E agrees with other measurements in the region. Natural fractures were observed at relatively low density within the rock formations, and most rock formations had less than 10 natural fractures observed per 100 m vertical borehole interval. Analysis of over 20,000 well fracture breakdown measurements provides constraints on the horizontal stress magnitudes. These data suggest shut-in pressure gradients of from 0.7-1.0 psi/ft (16-23 kPa/m), which may be an indicator of minimum horizontal stress at depth. Altogether, the data better defines the nature of subsurface stress conditions, fracture networks, and potential impact of large scale CO2 storage in key storage zones and caprocks in the Midwestern U.S. The information will be useful to provide siting and operating guidance for CO2 storage projects. This work allows a more realistic portrayal of risk factors related to CO2 storage in a region that is still heavily dependent on fossil fuels and also a set characterization protocols for other areas. The information will be useful to provide siting and operating guidance for CO 2 storage projects. Acknowledgements The research was part of the United States Department of Energy National Energy Technology Laboratory’s program to develop and validate technologies to ensure safe and secure CO 2 storage. This research was supported by U.S. Department of Energy’s National Energy Technology Laboratory under Award DE-FE0023330 and the Ohio Development Services Agency Ohio Coal Development Office under Grant D-14-16. Technical advice was provided by Dr. Samin Raziperchikolaee, Mark Kelley, John Miller, Joel Main, Amber Conner, Glenn Larsen, Ashwin Pasumarti and many others. References Barnes, D.A., Bacon, D., and Kelley, S. 2009. Geological sequestration in the Cambrian Mount Simon Sandstone: Regional storage capacity, site characterization, and large-scale injection feasibility, Michigan Basin. Environmental Geosciences, v. 16, n.3, p.163-183. Barree, R.D. and Miskimins, J.L. 2015. Calculation and Implications of Breakdown Pressures in Directional Wellbore Stimulation. SPE Hydraulic Fracturing Technology Conference, Woodlands, Texas, February 2015. SPE173356-MS. 21 p. Chiaramonte, L. 2009. Geomechanical Characterization and Reservoir Simulation of a Carbon Dioxide Sequestration Project in a Mature Oil Field, Teapot Dome, WY. Ph.D. Dissertation, Stanford University. Greb, S., Bowersox, J.R., Solis, M.P., Harris, D.C., Riley, R.A., Rupp, J.A., Kelley, M., and Gupta, N., 2012, Ordovician Knox carbonates and sandstones of the eastern midcontinent: Potential geologic carbon storage reservoirs and seals, in Derby, J.R., Fritz, R.D., Longacre, S.A., Morgan, W.A., and A., S.C., eds., The great American carbonate bank: The geology and economic resources of the Cambrian – Ordovician Sauk megasequence of Laurentia, AAPG Memoir 98, p. 469a-478a. Gronseth, J.M. and Kry, P.R. 1983. Instantaneous Shut-in Pressure and its Relationship to Minimum In Situ Stress. In Hydraulic Fracturing Stress Measurements, M.D. Zoback and B.C. Haimson, eds.), National Academy Press, Washington, D.C., p. 55-63. Hawkes, C.D., Bachu, S., Haug, K., and Thompson, A. 2005. Analysis of In-situ Stress Regime in the Alberta Basin,

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