Geomechanical Assessment of the Cincinnati Group As a Caprock

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Geomechanical Assessment of the Cincinnati Group as a Caprock

Thesis

Presented in partial fulfillment of the requirements for the degree Master of Science in the Graduate School of The Ohio State University

Matthew R. Hawrylak, B.S.

Graduate Program in Earth Sciences

2013

Thesis committee Dr. Jeffrey Daniels, adviser Dr. Ann Cook Dr. E. Scott Bair

Abstract

In this study, the Cincinnati Group, was investigated for its potential as a confining layer (caprock.) The Cincinnati Group is a thick layer of late–Ordovician calcareous shale that directly overlies the Utica/Point Pleasant throughout the Appalachian Basin as a potential seal for fluid injection and CO2 sequestration. The Cincinnati Group was deposited in a shallow sea environment in Late–Ordovician Laurentia in multiple transgressive–to–regressive sequences. The viability of the Cincinnati Group as a caprock was studied using petrophysical and geomechanical methods, including well log analysis and laboratory evaluation of lithology, permeability, and tensile strength.

Core samples of the Cincinnati Group were taken from the Aristech Well in Scioto

County. Logs were obtained from many locations across the state of Ohio. I use permeability and Poisson’s ratio measurements from the core, and traveltime, density, and porosity data from logs to calculate both multiphase fluid flow times and fracture initiation pressures for the Cincinnati Group at the location of each well log. I compare results to mineralogical data obtained via energy dispersive x–ray spectroscopy, which demonstrates that increasing shale content decreases permeability and increases fracture resistance.

At the location in Scioto County, the intrinsic permeabilities of core samples from a well were measured to be in the range of 0.001 to 0.705 mD, with an average value of

0.111 mD. These values resulted in calculated migration times of 3,700 years and 900 years for water and CO2–water mixture through the entire Cincinnati Group, which has a thickness of 795 at this location. Fracture gradient calculations predict an injection pressure of at least 0.81 psi per foot is required to induce a fracture at the base of the

Cincinnati Group rocks. Individual fluid migration time (0.215 feet/year at Scioto County site) and the prediction of the formation of fractures from each location were compared to values from similar studies in the literature and from communications with current operators in the Utica/Point Pleasant of Ohio for context. It was found that lower– bound calculations predict the physical characteristics of the Cincinnati Group are those of an excellent caprock capable of containing water injected under pressure, but the

Cincinnati Group requires further investigation to determine its potential for CO2 sequestration.

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Acknowledgments

I would like to thank my advisers, Jeff Daniels, Ann Cook, and E. Scott Bair. This research was made possible through funding from the Ohio Coal Development Office and the U.S.

Department of Energy. I would also like to thank Julie Sheets, Sue Welch, Alex Swift,

Mike Murphy, Kyle Shalek, Tingting Liu, and Nick Leeper of OSU Earth Sciences; Chris

Perry, Jim McDonald, Joe Wells , Mark Baronoski, Ron Riley, and Greg Schumacher of the Ohio Geological Survey; and Brian Mott of DLZ Engineering.

Vita

May 2007……………………………………..………………St. Edward College Preparatory High School May 2011……………………………...... ……..B.S., Geology, The Ohio State University September 2011...... Graduate Research Associate, Geology, The Ohio State University June 2012...... Intern, the US Army Engineer Research and Development Center January 2013...... Graduate Teaching Associate, Geology, The Ohio State University April 2013...... Distinguished Teaching Award, The Ohio State School of Earth Science June 2013...... Intern, Chevron North America Exploration and Production Company December 2013...... M.S., Geology, The Ohio State University

Fields of Study

Major Field: Earth Sciences

Table of Contents

Abstract ...... ii Acknowledgments...... iv Vita ...... v List of Tables ...... vii List of Figures ...... viii Chapter 1: Introduction…………………...... 1 Chapter 2: Geologic Setting…………………………………………………...... 6 Chapter 3: Methods……………………………………………………………………………………………………..12 Chapter 4: Results and Discussion………………………………………………………………………………..19 Chapter 5: Conclusions…………………………………………………………………………………………………28 References ...... 31 Appendix A: Cincinnati Group Picks from Gamma Ray Logs………………………………………….36 Appendix B: Laboratory Measurements…………………………………………..…………………………..48 Appendix C: Scioto County Fracture Gradient Calculations..………………………………………...53 Appendix D: Belmont County Fracture Gradient Calculations ……………………………………...60 Appendix E: Gallia County Fracture Gradient Calculations ……………………………………….....69

List of Tables

Table 1: Cincinnati Group Fluid Migration Times………………………………………………………….23

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List of Figures

Figure 1: Generalized stratigraphic column for east–central Ohio....………………………….....2 Figure 2: Sites used in this study.……...... ………………………………………...... 3 Figure 3: Map of horizontal Utica wells in Ohio ………………………...... 4 Figure 4: Paleogeographic map of Laurentia during the late Ordovician...... 7 Figure 5: Generalized stratigraphic column of Ohio……………………………………………...... 8 Figure 6: Relation between shale acoustic parameter and reservoir fluid pressure gradient…………………………………………….……………………………………………...... 16 Figure 7: Allen County well gamma ray curve…………………………………………….…………………37 Figure 8: Ashtabula County well gamma ray curve……………………………………………...... 38 Figure 9: Belmont County well gamma ray curve……………………………………………...... 39 Figure 10: Columbiana County well gamma ray curve……………………………………………...... 40 Figure 11: Fairfield County well gamma ray curve……………………………………………...... 41 Figure 12: Gallia County well gamma ray curve……………………………………………...... 42 Figure 13: Henry County well gamma ray curve……………………………………………...... 43 Figure 14: Marion County well gamma ray curve……………………………………………...... 44 Figure 15: Medina County well gamma ray curve……………………………………………...... 45 Figure 16: Sandusky County well gamma ray curve……………………………………………...... 46 Figure 17: Scioto County well gamma ray curve……………………………………………...... 47 Figure 18: Warren County well gamma ray curve……………………………………………...... 48 Figure 19: Scioto County Intrinsic Permeability Measurements………………………………...... 50 Figure 20: Scioto County SEM/QEMSCAN Results……………………………………………...... 51

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Figure 21: Scioto County AR2–15 unconfined compression test……………………………….....52 Figure 22: Scioto County AR2–16 unconfined compression test……………………………...... 53 Figure 23: Scioto County P–wave curve: compressional trend and deviation…………...... 55 Figure 24: Scioto County density log………………………………………………………………...... 56 Figure 25: Scioto County reservoir fluid pressure gradient………………………………...... 57 Figure 26: Scioto County reservoir fluid pressure………………………………………………………...58 Figure 27: Scioto County fracture gradient……………………………………………………………….....59 Figure 28: Scioto County fracturing pressure………………………………………………………………..60 Figure 29: Belmont County dipole sonic logs………………………………………………………………..62 Figure 30: Belmont County P–wave curve: compressional trend and deviation……………63 Figure 31: Belmont County density log………………………………………………………………...... 64 Figure 32: Belmont County reservoir fluid pressure gradient………………………………...... 65 Figure 33: Belmont County reservoir fluid pressure………………………………………………….....66 Figure 34: Belmont County Poisson’s ratio……………………………………………………………….....67 Figure 35: Belmont County fracture gradient……………………………………………………………….68 Figure 36: Belmont County fracturing pressure…………………………………………………………...69 Figure 37: Gallia County dipole sonic logs………………………………………………………………...... 71 Figure 38: Gallia County P–wave curve: compressional trend and deviation...... 72 Figure 39: Gallia County reservoir fluid pressure………………………………………………………....73 Figure 40: Gallia County reservoir fluid pressure gradient………………………………...... 74 Figure 41: Gallia County density log………………………………………………………………...... 75 Figure 42: Gallia County Poisson’s ratio………………………………………………………………...... 76 Figure 43: Gallia County fracture gradient………………………………………………………………...... 77 Figure 44: Gallia County fracturing pressure ………………………………………………………………..78

Chapter 1: Introduction

Fluids are currently being injected into deep formations for the purposes of the production of hydrocarbons and the storage and sequestration of liquid waste (oil field brine). Injection tests of CO2 into the subsurface have also been conducted as a potential method of sequestration. Although thousands of feet of rock (much of it low permeability shale) separates the freshwater zone from the potential injection targets

(see Figure 1), there is concern among the general public that fractures may propagate upward from the Utica Shale and enable hydrocarbons, brine water, and chemicals to migrate upward toward near-surface freshwater aquifers. To date there is no evidence of any upward movement of injected fluids. An overlying low–permeability and fracture-resistant layer would prevent upward migration of hazardous fluids on human timescales. Also, in the case of carbon storage, a proven caprock could also serve to contain sequestered CO2 in the Trenton/Lexington Limestone in the southwestern portion of Ohio. The lower portion of the Cincinnati Group, dominated by late

Ordovician calcareous shale that overlies the Utica, may provide a sufficiently low permeability and geomechanically sound layer that is needed to halt leakage of hydrocarbons and other fluids.

This project grew out of collaboration between the Ohio Geological Survey and the

Figure 1: Generalized stratigraphic column for east–central Ohio (Wickstrom 2012).

Subsurface Energy Materials Characterization and Analysis Laboratory (SEMCAL) at The

Ohio State University School of Earth Sciences to study caprock in several wells in Ohio.

The Geological Survey proposed a list of relevant problems facing the state of Ohio, and

SEMCAL acquired Department of Energy funding to perform subsurface characterization, particularly relating to the emerging shale gas activity in the 2

Figure 2: Sites used in this study. The three main sites, Scioto County with core, and Gallia and Belmont Counties with dipole sonic, are marked in blue. Other sites were used to pick the top and bottom of the Cincinnati Group.

Appalachian Basin. The aim of this research was to assess the viability of the Cincinnati

Group to serve as a caprock for both CO2 sequestration and for containing hazardous fluids associated with hydrocarbon exploration. Laboratory and geophysical well log measurements were used to assess the fracture gradient (resistance to fracturing) and matrix permeability, focusing on several discrete locations across the state of Ohio

Figure 3: Map of all horizontal Utica wells drilled in Ohio through 6/29/2013. Activity is limited to the eastern half of the state. Courtesy of Mackenzie Land and Exploration Ltd. 4

(see Figure 2). Although gas production from the Utica Shale is occurring only in eastern

Ohio (see Figure 3), the Cincinnati Group may still have potential to serve as a caprock for CO2 sequestration in the southern and western parts of the state. The sites were chosen based on the availability of core and dipole sonic (both compression and shear) logs. Core was obtained from the well in Scioto County (known as the Aristech Well).

Dipole sonic logs (as well as gamma ray, density, and porosity) were available from

Gallia and Belmont Counties. Additional sites were chosen to provide adequate coverage of the state and account for lateral changes.

Chapter 2: Geologic Background

During the Late Ordovician (460-445 Ma), the entire state of Ohio was submerged under a shallow, inland sea (see Figure 4). To the east, the Iapetus Ocean was closing, narrowing the gap between Laurentia (now North America) and Baltica (now Europe).

The closing of the ocean resulted in the Taconic Orogeny and the building of the early

Appalachian Mountains. Near the present day border between West Virginia and

Virginia, back–arc volcanism built a chain of islands which supplied siliciclastic sediment to the Appalachian Basin. Carbonate production in this shallow sea, with intermittent terrigenous sediment supply from the east, resulted in the deposition of a thick sequence of calcareous shale now known as the Cincinnati Group. It was deposited as a prograding (to the North) sequence on a carbonate ramp (Quinlan 1984, Bair 2012). The extent of the Cincinnati Group spans the entire state of Ohio, although in the southwestern portion of the state it is more commonly known by its individual member names. They are, from oldest to youngest, the Kope Formation, the Fairview Formation, the Grant Lake Limestone, the Arnheim Formation, the Waynesville Formation, the

Liberty Formation, the Saluda Formation, the Whitewater Formation, and the Drakes

Formation (see Figure 5). The subdivision of the Cincinnati Group around the Cincinnati area does not reflect lateral changes in stratigraphy from the rest of the state; the

Figure 4: Paleogeographic map of Laurentia (North America) during the late Ordovician, circa 450 Ma (Blakey, 2011).

differing names are simply a result of geography. These formations in total are interpreted as three shallowing upward sequences divided by unconformities. Each sequence consists of a sharp bottom boundary overlain by limestone, which slowly becomes shaley upwards, until it grades completely into shale (Schramm, 2011).

The following summaries of Edenian (early Cincinnatian, circa 450–448.3 million 7

Groupthe southeastern Notedivisions of Cincinnati in 1990). (Stewart, of column stratigraphic Figure5:Ohio Generalized Ohio. 8 years old) are derived from the Master of Science thesis of Schramm (2011). These descriptions apply most specifically to the region surrounding the city of Cincinnati: southwest Ohio, north–central Kentucky, and eastern Kentucky. Moving away from this region and across Ohio, the Cincinnati Group undergoes some lateral variations, but the character of the mineralogy generally remains the same: sequences of dirty, fossiliferous limestone, which grade upwards into more shaley sediment. The formations will be described from oldest to youngest.

The Kope Formation is interbedded shale and limestone, in a roughly three–to–one proportion. This blue–gray calcareous shale represents the initial phase of a progradation, in the distal facies below storm wave base. The Fairview Formation, formerly known as the Mount Hope and Fairmont formations, overlies the Kope. The transition from Kope to Fairview is marked by prominent limestone beds replacing the shaley and silty beds. The Fairview represents the next facies nearer to shore from the

Kope, between the fair-weather and storm wave bases. It consists of roughly equal amounts of brown to gray limestone and shale, often in meter–scale couplets, which represent a complicated history of repeated minor transgressions and regressions.

Overlying the Fairview is the Grant Lake Formation (also known as the McMillan), which is composed mostly of limestone, with some interbedded shale. The Bellevue

Member is a 10–12 foot thick fossiliferous limestone body, with only minor thin, wavy siltstone beds. The overlying Corryville Member is composed of thick, planar alternating beds of shale and limestone. Overlying the Corry is the Mount Auburn Member, which

9 is composed of interbedded limestone nodules and blue shales. There are three geologic groups within the Mount Auburn, a lower mostly limestone unit, a middle unit composed of mainly shale, and an upper dominantly limestone unit.

Continuing upward in the stratigraphic column, we enter the Maysvillian Stage (Early to Mid-Cincinnatian, circa 448.3–446.7 million years old), which encompasses the upper portion of the Grant Lake, the Arnheim Formation, and the lower Waynesville formation. The Arnheim Formation is composed of shaley mudstone and interbedded limestone. Next is the Waynesville Formation, which marked a shallowing that resulted in shaley deposits grading upwards into dirty carbonates.

The next stage is the Richmondian, which includes the upper Waynesville, the Liberty formation, the Saluda Formation, and the lower Whitewater Formation. The Liberty

Formation is mostly fossiliferous carbonate, with some interbedded siltstones. The

Saluda is a predominantly dolomitic mudstone facies, which represents the shallowest point in the regression sequence. Thus, the Saluda–Whitewater contact represents the beginning of a transgressive sequence. The Whitewater is composed of mudstone, as the depositional environment shifted to deeper water. Above the Richmondian is the

Gamachian stage, which contains the upper Whitewater and the Drakes Formation. The

Drakes Formation is made up of dolomitic mudstone, and represents a minor regression superimposed on the overall transgressive stage (Schramm, 2011). See Figure 5 for a stratigraphic column.

There is some debate as to the relative ages of Cincinnatian strata. The above

10 descriptions follow the school of thought of Holland and Patzkowsky (1996) and Cuffey

(1998). Other interpretations, such as that favored by the Ohio Geological Survey, place nearly the entire Cincinnati Group in the Edenian Stage, with only the upper portion of the Liberty and the Whitewater belonging to the Maysvillian Stage (Ryder 2009).

Regardless, it is generally understood that the Edenian represents a sealevel high stand, the Maysville represents a regressive stage, and the Richmondian is a subsequent low stand (Schramm 2011, Quinlan 1984). This results in the Cincinnati Group being most carbonate–rich at the bottom and more clay–rich moving upwards, with many interbeds of both types of rocks interspersed, reflecting the complicated history of transgressions and regressions.

Chapter 3: Methods

Core samples and well logs were provided by the Ohio Geological Survey. The core samples were used in a variety of laboratory tests including gas–probe permeametry, geomechanical stress–strain testing, and scanning electron microscopy. Mineralogy was investigated through QEMSCAN (Quantitative Evaluation of Minerals by SCANning electron microscopy) mapping (Butcher 2012). QEMSCAN quantifies mineralogy by comparing energy dispersive x–ray spectra (EDS) to a mineral database. Well logs, in particular density and dipole sonic traveltime logs, were manipulated in order to calculate the fracture gradient. Gamma ray logs were also used to pick the tops and bottoms of the Cincinnati Group in each well (see Figures 7–18 in Appendix A). The relationships between mineralogy, permeability, and fracture gradient were investigated by comparing laboratory and well-log measurements to scanning electron microscope (SEM) images and QEMSCAN data.

Well Log Interpretation

Well logs provided a wide array of relevant information and were readily available from many locations across the state. Gamma ray logs were used to pick the top and bottom of the Cincinnati Group. A gamma ray log works by detecting the natural

12 radiation from potassium, thorium, and uranium in clay minerals, which are more abundant in shales. The output of a gamma ray log is measured in API, an American

Petroleum Institute scale based on laboratory measurements of typical shales (Reynolds

2011). The gamma ray signature of the Cincinnati Group should, in theory, be easily distinguishable from the adjacent formations due to mineralogical variations. The

Cincinnati Group is bound by the Clinton Sandstone above and the Utica/Point Pleasant or Trenton/Lexington Limestone below. As a highly shaley carbonate, the Cincinnati

Group generally has a higher API count than the Clinton, Trenton/Lexington, and

Utica/Point Pleasant (Carr 2013). However, gamma ray logs showed great lateral variability between sites, both within the Cincinnati itself and in the character of the formation contacts. An annotated drilling report from the Scioto County Aristech Well

(Rapp, 1991) and a type–log report (Daniels, 2012) assisted in picking the tops and bottoms in some other wells.

Sonic logs (Battelle, 2007; Bakerwell, 2004) were used to determine in situ values of

Poisson’s ratio and predict the formation pressure. A sonic logging tool works by measuring the transit time of seismic waves through the formation from a source to a receiver; the traveltime is a function of the density and elasticity of the rock through which they propagate. Gamma–gamma density logs (Battelle, 2007; Bakerwell, 2004) were used to determine the overburden stress. In density logging, a radioactive source emits gamma radiation, which interacts with the electrons in the rock. A detector measures the amount of returning gamma rays, which is proportional to the electron

13 density of the formation, which, in turn, is proportional to the formation bulk density.

Values from Poisson’s ratio and overburden stress calculations were then input into fracture gradient calculations. Poisson’s ratio quantifies the relationship between transverse and axial strain in response to stress. It is a factor in determining the initiation and orientation of fractures within a stress field. The formation pressure or reservoir fluid pressure is the pressure exerted by fluids within pores; this depends on the hydrostatic pressure, or the weight of a column of water from sea level to the formation depth, and may be increased if fluid is unable to escape from occluded pores during compaction. The overburden stress is the weight of the overlying column of rock.

Geomechanical Testing and Fracture Gradient Calculations

In addition to the calculations from sonic logs, Poisson’s ratio was also determined via geomechanical stress–strain testing on core samples from the Scioto County Aristech

Well. Stress–strain testing was carried out on samples AR2–15 (2,905 feet depth) and

AR2–16 (3,000 feet) at DLZ Environmental Engineering Company. The geomechanical tests consisted of uniaxial, unconfined compression in a hydraulic press until failure.

The destructive nature of these compression tests made opportunities to obtain core limited; I received permission to conduct such tests on only two samples. These tests provided elastic properties of the rock, most importantly Poisson’s ratio, which was compared to values calculated from sonic logs and used in further fracture gradient

14 calculations. See Figures 21 and 22 (Appendix B) for the results of the compression tests performed at DLZ.

Fracture gradient is the pressure required to produce a fracture per unit of depth. It may be thought of as the pressure required to produce a fracture at a given depth, divided by that depth. Fracture gradient is a useful parameter to assess a formation’s resistance to fracturing, while factoring out the depth term for the sake of comparison.

It may be calculated from pressure data (overburden and pore pressure) and Poisson’s ratio, using this relation (Eaton, 1969):

Gif = [ѵ/(1-ѵ)](Gob – Gpp) + Gpp where Gif is the fracture gradient, ѵ is Poisson’s ratio, Gob is the overburden pressure gradient, and Gpp is the pore pressure gradient. Poisson’s ratio was calculated from traveltime logs (DTCO and DTSM) using the relation from Zhang and Bentley (2005):

ѵ = [½ (DTCO/DTSM)2 – 1]/[(DTCO/DTSM)2 – 1]

Here DTCO is the compressional wave traveltime, and DTSM is the shear wave traveltime. The overburden pressure was determined via this simple relation (e.g.

Turcotte and Schubert, 2002):

σy = ρgy

Here, σy is the overburden pressure, ρ is the density of the overlying rock, g is the acceleration due to gravity, and y is the depth. For the density log, calculations incorporated the average density for the entire overlying body of rock at each depth step.

Figure 6: Relation6 between shale acoustic parameter Δtob(sh) – Δtn(sh) and reservoir fluid pressure gradient (Hottman, 1965). (Hottman, 1965)

The pore pressure gradient was calculated from via a relation to compressional wave traveltime from Hottman and Johnson (1965). In this method, the normal compaction

16 trend resulting from the overburden pressure is determined from a P–wave curve (see

Figures 23, 30, and 38; Appendices C, D, and E), and deviation from this trend is attributed to over–pressuring from fluid within the pores. Then, an experimentally derived curve relates the P–wave curve deviation from the normal trend to the reservoir fluid pressure gradient. I fit the curve seen in Figure 6 (Hottman and Johnson, 1965) to a polynomial to obtain the reservoir fluid pressure gradient. Then, using the overburden pressure gradient, the pore pressure gradient, and Poisson’s ratio, I calculated the fracture gradient for the Scioto County Aristech Well, the Belmont County well, and

Gallia County well, using the above relation from Eaton (1969).

Mineralogy and Permeability

Another chief physical property that determines the quality of a caprock is permeability, which can be quantified via a gas probe permeameter. This instrument works by injecting gas through a sample and measuring the rate of pressure decay. A gas injection rod is lowered onto a flat sample surface, creating an air-tight seal. The injected gas must then flow through the sample itself, and the rate of pressure decay is proportional to the permeability via Darcy’s Law. Klinkenberg error is reduced by using low injection pressures. However, gas slippage enhances apparent permeability values, so results may be thought of as an upper bound (McPhee and Arthur, 1991). Five core samples were analyzed via gas probe permeameter, all from the Scioto County Aristech

Well. Here, the Cincinnati Group has a depth range of 2,210 to 3,005 feet. Samples

17 were selected based on covering the available depth range (2,800–3,005 ft) and representing the mineralogical variability evident through visual inspection (degree of clay content in carbonate). Samples were taken at depths of 2,801 feet (AR2–1), 2,863 feet (AR2–2), 2,928 feet (AR2–3), 2,948 feet (AR2–4), and 2,972 feet (AR 2–5). Within this depth range, all samples appeared to be composed of shaley carbonate of varying proportions. Other Aristech Well Cincinnati Group samples were not available for cutting, due to the necessity to preserve them for other SEMCAL experiments.

The mineralogy of core samples from the Cincinnati Group was assessed quantitatively via scanning electron microscopy on an FEI Quanta 250

SEM equipped with QEMSCAN quantitative mineralogy software. This provides mineral maps that allow for qualitative assessment of the mineralogy that lines pores, as well as quantitative mineralogy data of samples. The FEI instrument enabled a comparison of changes in permeability with mineralogy changes made evident through QEMSCAN analysis. Mineralogy was assessed for samples AR2–2 (2,863 feet depth) and AR2–14

(2,672 feet depth). Only a small portion of sample AR2–14 was available, just enough to make a thin section for SEM analysis (for this study and other SEMCAL experiments), but not sufficient to produce a slab for permeametry. However, this sample was selected for QEMSCAN analysis due to its distance from the basal carbonate–rich portion of the

Cincinnati Group; the gradational mineralogical changes were evident at this distance.

See Figure 20 in Appendix B for results.

Chapter 4: Results and Discussion

Assessment of matrix permeability and fracturing toughness produced quantitative results that were then compared to values from the literature. Direct measurements of physical properties at the three main measurement sites (Scioto County, Belmont

County, and Gallia County) were used to extrapolate the fluid flow and fracture strength calculations to predict the response of the Cincinnati Group at other well sites.

Cincinnati Group Thickness

Determining the thickness of the Cincinnati Group at each study location was essential for calculation inputs and context. Analysis of gamma ray logs showed the

Clinton Sandstone above was distinct from the shaley upper Cincinnati due to the sharp increase in the gamma ray signature moving from the sand to the shale. The boundary with the Utica/Point Pleasant below manifested gradationally on the gamma ray log, typically as a gradual reduction in API. Some wells were missing depth sections, which made picking tops and/or bottoms difficult. For example, in the Belmont County area, the Cincinnati Group is quite deep, with a top at approximately 7,800 feet. No available wells penetrated deep enough to find the bottom of the Cincinnati Group. A thickness of roughly 1,700 feet was estimated by combining well log information (top) with data

19 from a depth to the top of the Utica Shale (equivalent to the bottom of the Cincinnati) map (Murphy 2010). See Table 1 for information on the top, bottom, and thickness of the Cincinnati at each well site.

Fluid migration through matrix permeability

Permeability results were compared to typical CO2 and water migration times from a

USGS CO2 migration model (Burke, 2012). As previously mentioned, permeability measurements were obtained via gas probe permeameter on core samples from the

Scioto County Aristech Well. The tests required a flat surface for accurate measurements, which required core samples needed to be cut. This made opportunities to obtain core limited, as it is always desirable to maintain as much core as possible. I could only obtain core with permission to perform destructive tests from the Aristech Well. The limited results obtained for permeability ranged from 0.001 to

0.705 millidarcies, with an average value of 0.111 mD over a depth range from 2,800 to

2,970 feet (see Figure 19, Appendix B). These permeability measurements were applied to all other well locations in water and CO2 migration time calculations. The validity of this extrapolation is not quantitatively precise; however, the comparison of gamma ray curves for the Cincinnati among well sites (see Figures 7–18, Appendix A) indicate that the basal Cincinnati Group at the Scioto County site is even more carbonate–rich than typical. Higher gamma ray API values at the other sites suggest a higher concentration of clay minerals and lower permeability at the other sites. As a result, the Scioto County

Aristech Well shaley carbonate permeability measurements may be thought of as a rough lower bound for the Cincinnati Group.

Scioto County permeability results compared favorably to sites selected for assessment in the USGS CO2 migration model report (Burke, 2012). Results were put into context using single and multiphase fluid flow equations. At the Scioto County

Aristech Well location, calculations indicated that the Cincinnati Group has sufficiently low permeability to contain fluids for several thousand years. Calculations for the migration of water under pressure through the Cincinnati Group at depth at the Scioto

County site resulted in hydraulic conductivities around 0.215 feet per year. This corresponds to a migration time of roughly 3,700 years through the entire thickness of

795 feet of Cincinnati Group, assuming vertical migration only through matrix permeability, using this relation for hydraulic conductivity (Schwartz and Zhang, 2003):

K = kρg/µ

Here, K is the hydraulic conductivity, k is the intrinsic permeability of the formation, ρ is the fluid density (of a typical formation brine with a concentration of 100,000 mg/L total dissolved solids), g is the acceleration due to gravity, and µ is the fluid viscosity (Dittman

1977). In my conceptual model, the brine density varied from 1,033 to 1,055 kg/m3 over the depth range of the Cincinnati Group in the Scioto County well. See Table 1 for information on thickness and migration time for water through the Cincinnati Group at various locations, assuming the same permeability values apply at every location.

Additives to the water were neglected. Common additives to hydraulic fracturing fluid

21 include compounds that increase viscosity, making these migration time estimates conservative in that regard. Of course, the presence of fractures would provide additional pathways for fluid transport, and thus increase permeability and decrease migration time. The possibility of fracture–enhanced fluid migration makes studying the fracture gradient all the more important (see next section).

The problem of CO2 migration is slightly more complicated; the approach proposed by MacMinn et al. (2011) is used here. The migration time is thought of in a manner similar to the simple hydraulic conductivity relation above, except with additional parameters for CO2 saturation of the formation brine, relative permeability, and intrinsic porosity of the formation (relevant due to significant capillary action of CO2 into surrounding rock).

K = Δρgk(kr/µ)/[(1–Sw)φ]

Here Δρ is the density difference between the formation brine water and the CO2, kr is the relative permeability, µ is the fluid viscosity, Sw is the water saturation, and φ is the

3 porosity. The density of C02 varied from 1.33 to 1.72 kg/m over the depth range of the

Cincinnati Group in the Scioto County well, based on the temperature and pressure conditions present (Span and Wagner, 1996). Note that the water saturation and CO2 saturation fractions must add up to one. A number of assumptions had to be made to make use of this equation. The water–to–CO2 ratio was taken to be one–to–one, based on target values from multiple studies of multiphase fluid interaction at depth (Bennion,

2005; Burke, 2012; Delshad, 2010; and MacMinn, 2011). Relative permeability may be

Well Top Cinci Bot Cinci Thickness H20 tm CO2 tm Max Frac Location (ft) (ft) (ft) (yrs) (yrs) Vol (ft3) Allen 350 1,040 690 3,200 800 10,350 Ashtabula 3,510 5,300 1,790 8,300 2,000 26,850 Belmont 5,800 7,500 1,700 7,900 1,900 25,500 Columbiana 4,870 7,875 3,005 14,000 3,400 45,075 Fairfield 2,990 4,140 1,150 5,300 1,300 17,250 Gallia 3,700 5,000 1,300 6,000 1,500 19,500 Henry 945 1,720 775 3,600 900 11,625 Marion 430 1,150 720 3,300 800 10,800 Medina 2,800 3,840 1,040 4,800 1,200 15,600 Sandusky 595 940 345 1,650 400 5,175 Scioto 2,210 3,005 795 3,700 900 11,925 Warren 20 820 800 3,700 1,000 12,000

Table 1: Here information for the top, bottom, and thickness, listed in feet, is given for the Cincinnati Group at each well location. Estimated migration times for water and CO2 through matrix permeability are listed in years. Core for direct measurement of permeability was available for only the Scioto County Aristech Well, so these permeability numbers were applied to all locations. The maximum allowable single– fracture injection volume is also displayed, based on the typical induced fracture width and length, combined with the vertical thickness of the Cincinnati at a given location.

thought of as a saturation fraction that governs the mobility of the suspended phase in multiphase fluid flow (Schwartz and Zhang, 2003). This parameter was taken to be 0.5, based on target numbers from the same studies. Finally, the viscosity of CO2 was taken to be independent of pressure. The viscosity of CO2 actually increases with increasing pressure, which would increase migration times (Heidaryan, 2011). However, for the worst–case–scenario, the lowest possible viscosity of ambient temperature and pressure is used as an absolute lower bound on migration time. In addition, since the

CO2 would be suspended in water, which behaves as nearly incompressible, the viscosity would not be affected by variations in pressure as much as pure CO2. Using the

MacMinn (2011) relation yields a CO2 conductivity of 0.892 feet per year, which corresponds to a migration time of around 900 years at the Scioto County Aristech Well site. This is perhaps not a satisfactory containment time, especially considering the possibility of migration through preexisting fractures, indicating that this particular site may not be suitable for CO2 sequestration. However, more desirable CO2 sequestration sites are available; particularly the Ashtabula, Belmont, and Columbiana County sites

(see Table 1).

Initiation of Fractures

Poisson’s ratios determined from the unconfined uniaxial compression tests were systematically lower than Poisson’s ratios calculated from dipole sonic logs. This is most likely due to the absence of confining pressure. The geomechanical tests on Scioto

County core had Poisson’s ratios of 0.15 to 0.19 (Figures 21 and 22), whereas calculations from Belmont and Gallia County well sonic logs suggested values of 0.25 to

0.30 (Figures 34 and 42; Appendices D and E). This discrepancy may also be explained by the degradation of the rock during the coring process, and afterward from exposure.

This weakening and the lack of confining pressure likely caused Poisson’s ratio to be lower in the Scioto County Aristech Well core samples. Thus, the fracture gradient for

24 the Scioto County Aristech Well is calculated using Poisson’s ratios from the geomechanical tests as well as a typical value found in the Belmont and Gallia wells.

Results from fracture gradient calculations were compared to parameters from a typical Chesapeake Energy hydraulic fracturing operation. Values for injection pressure and volume per hydraulic fracturing stage were obtained through speaking with

Chesapeake geologists and technicians while visiting a well site where hydraulic fracturing was taking place. A typical injection pressure is in the range 7,800 – 9,200 pounds per square inch, and a typical injection volume is around 6400 barrels (268800 gallons) of fluid per stage (Elasmer, 2013). These values apply to wells in eastern Ohio, where the Utica was being hydraulically fractured at depths of 6,000 to 8,000 feet. This means the fracture gradient would need to be at or below 1.2–1.3 psi per foot to initiate a fracture. These values agree to within 20% of the calculation results from Scioto,

Belmont, and Gallia Counties (Figures 27, 35, and 43; Appendices C, D, and E). Since the vast majority of energy will be dissipated within the Utica/Point Pleasant, the Cincinnati

Group appears to be more than adequate to act as a fracture barrier for fluid injection below. Typical CO2 sequestration operations use pressures around 2,500 psi at depths of at least 3,000 feet (fracture gradient of 0.83 psi/ft), making the Cincinnati Group more than adequate to prevent fractures at all three locations (Delshad, 2010). See the

Figures 23–44 (Appendices C, D, and E) for graphical depictions of the step–by–step results for fracture gradient calculations from all three counties.

In addition, simple calculations were performed for the volume of water that could

25 be pumped into one fracture of typical width (0.3 inches) and length (600 feet) propagating upwards through the entire Cincinnati Group at each well location

(Geertsma and de Klerk, 1969; Geertsma and Haafkens, 1979; and Perkins and Kern,

1961). Fluid volumes were on the order of 1000–10000 barrels (see Table 1). I refer to this volume as the maximum allowable single-fracture volume. A more realistic conceptual model would incorporate a network of fractures rather than one, so my calculations are an extreme lower bound for maximum allowable injection volume.

Regardless of geometry, the injection pressure remains the same; distributing the dissipation of energy into a three dimensional network with a larger areal footprint has the result of decreasing the maximum possible vertical propagation distance.

Mineralogy

The effects of mineralogical changes on permeability and fracture toughness were considered. Special attention was directed toward assessing the relationships among the type of rock cementation and geomechanical properties. Visual inspection and SEM analysis of core samples showed that fractures were uncommon, but their presence and effects on both the geomechanical yield strength and the laboratory permeability measurements cannot be ruled out. However, great care was taken to select portions of the core that appeared to be intact.

Of the two samples on which quantitative mineralogy data was collected, AR2–15 was shallower (2905 feet) and more shaley, while AR2–16 was deeper (3000 feet) and

26 more carbonate–rich (see Figure 20, Appendix B). This is in line with the stratigraphic observations outlined previously, denoting a transgressive sequence (Schramm, 2011;

Holland and Patzkowsky, 1996,; Cuffey, 1998). In the lower Cincinnati Group, grains are bound together with calcite cement/matrix, and stratigraphically upwards, grains are enclosed in a clay matrix. Comparison of mineralogical and geomechanical analyses from Scioto County samples shows a decrease in fracture gradient that coincides with a decrease in gamma ray API in the carbonate–rich lower portion of the Cincinnati Group.

The gamma ray signature from the Gallia well indicates a similar pattern of a clay–poor base grading upwards into clay–dominated rock (the Belmont County well does not penetrate deep enough to be conclusive). Thus, the wells in Gallia and Scioto Counties show a decrease in the fracture gradient at the same points where the gamma ray curve decreases, suggesting a positive correlation between clay content and fracture toughness. In addition, it was found that as the mineralogy shifted from clay–rich to clay–poor with increasing depth, the intrinsic permeability increased.

Chapter 5: Conclusions

The intention of this study was to determine the viability of the Cincinnati Group as a caprock. Although thousands of feet of low permeability rock separate potential targets from the base of potable groundwater, a sound caprock would provide even more security. A case study of the caprock potential of the Cincinnati Group at several locations is presented, and a path to further similar studies is suggested. Caprock assessment was conducted on micro (laboratory permeability and geomechanical), and meso (well logs) scales. The purpose of these tests is a demonstration of caprock viability testing, not an all–encompassing assessment of the entire Cincinnati Group.

Only around the Scioto County Aristech Well, from which core samples were obtained, is there enough information to say anything definitive regarding the viability of the

Cincinnati Group as a caprock. However, it is hoped that this study can serve as a baseline prediction of the potential of the Cincinnati Group to contain fluids at many other sites across the state. To be certain, similar studies should be conducted at other sites, with core sample, well-log, and seismic mapping of faults. In addition, borehole televiewer could be used to determine the orientation and frequency of pre–existing fractures. Pressure and permeability data could also be constrained using drill stem tests.

As to the hypothesis originally proposed, that the Cincinnati Group has sufficiently low permeability and high fracture resistance to serve as a caprock for fluid injection and CO2 sequestration, conclusions may be drawn only where there is adequate data.

Inferences at other locations are based on extrapolation of parameters. Data coverage was most complete at the Scioto County Aristech Well, where both logs and core were available. Other locations had only logs, and data obtained from Aristech core had to be extrapolated. Given the uncertainties inherent in the calculations in this study, these extrapolations are adequate for the intended demonstration.

The outcome of these predictions is generally that the Cincinnati Group is sufficient to confine injected water, but may be inadequate for CO2 sequestration. The ratio of

CO2 to water is a significant factor that cannot be accounted for through the available

data. To make a full assessment, data for CO2 saturation of formation brine at sequestration sites is necessary. The fluid migration time estimates, especially those for

CO2–brine mixture, should be thought of as lower bounds. It is likely that the target

50% CO2 saturation is not attainable, as it is presented as the ideal scenario (Bennion,

2005; Burke, 2012; Delshad, 2010; and MacMinn, 2011), indicating that migration time would shift closer to the water situation.

My final conclusions are that the Cincinnati Group is more than adequate to serve as a caprock for fluid injection at the Scioto County location, is likely to be capable of containing water across the state, and warrants further investigation in several locations, namely Ashtabula, Belmont, Columbiana, Fairfield, Gallia, Medina, and

Warren Counties for CO2 sequestration potential. To test these locations, core analysis similar to that conducted from the Aristech Well should be carried out. In addition, it is important to scan any potential injection site via seismic for preexisting faults. This study serves to suggest potential sites, but cannot fully clear them for use.

References

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Appendix A: Cincinnati Group Picks from Gamma Ray Logs

The following section depicts gamma ray logs from each well location. The tops and bottoms of the Cincinnati were picked based on the contrast of the expected moderate to high API shaley carbonate from the cleaner sand of the Clinton above and the more carbonate rich Utica/Point Pleasant or Trenton/Lexington below.

Cincinnati Group

Utica/Pt. Pleasant

Figure 7: Allen County well gamma ray curve used to pick the top and bottom of the Cincinnati Group

Cincinnati Group

Utica/Pt. Pleasant

Figure 8: Ashtabula County well gamma ray curve used to pick the top and bottom of the Cincinnati Group.

Cincinnati Group

Figure 9: Belmont County well gamma ray curve used to pick the top of the Cincinnati Group. The well did not penetrate deep enough to pick the bottom. 39

Cincinnati Group

Figure 10: Columbiana County well gamma ray curve used to pick the top and bottom of the Cincinnati Group. 40

Boundary uncertain

Cincinnati Group

Figure 11: Fairfield County well gamma ray curve used to pick the bottom of the Cincinnati Group. A missing section makes the top boundary uncertain. It was estimated from OGS cross sections (OGS 2006). 41

Cincinnati Group

Figure 12: Gallia County well gamma ray curve used to pick the top and bottom of the Cincinnati Group. 42

Cincinnati Group

Figure 13: Henry County well gamma ray curve used to pick the top and bottom of the Cincinnati Group. 43

Cincinnati Group

Utica/Pt. Pleasant

Figure 14: Marion County well gamma ray curve used to pick the top and bottom of the Cincinnati Group.

Cincinnati Group

Utica/Pt. Pleasant

Figure 15: Medina County well gamma ray curve used to pick the top and bottom of the Cincinnati Group. 45

Cincinnati Group Boundaries uncertain Utica/Pt. Pleasant

Figure 16: Sandusky County well gamma ray curve. Due to missing log in the section, the boundaries of the Cincinnati Group are uncertain. The estimated top and bottom are 595 and 940 feet, respectively (Murphy, 2010; OGS, 2006).

Cincinnati Group

Figure 17: Scioto County well gamma ray curve used to pick the top and bottom of the Cincinnati Group. 47

Cincinnati Group

Utica/Pt. Pleasant

Figure 18: Warren County well gamma ray curve used to pick the top and bottom of the Cincinnati Group. 48

Appendix B: Laboratory Measurements

The following section depicts the results of laboratory measurements: permeametry,

SEM/QEMSCAN, and unconfined compression tests.

2012).

from core from the Scioto County Scioto County the from core from

migration model (Burke model migration

to a USGS CO USGS a to

via gas probe permeameter probe via gas

of years, according according years, of

for several tens of thousands of tens several for

. The Cincinnati Group appears to have sufficiently low permeability (over a depth range of several hundred hundred of several range a depth (over permeability low sufficiently have to appears Group The Cincinnati .

Results of permeametry measurements obtain measurements of permeametry Results

Figure 19: Figure Well Aristech fluids contain to feet)

Quartz 5.05% Others 4.81% Illite/muscovite 70.40% Calcite 0.42% K–feldspar 1.28%

<2670 ft

< 2863 ft

Quartz 9.95% Others 1.30% Apatite 0.61% Illite/muscovite 17.37% Figure 20: Results of QEMSCAN quantitative mineralogy on Pyrite 0.92% thin sections from core from the Scioto Co. Aristech Well. The Dolomite 3.54% Cincinnati Group is carbonate–rich at the base and becomes Calcite 61.55% more clay–rich moving upward. 51 Plagioclase 2.12% K–feldspar 2.66%

Figure 21: Results of the uniaxial compression test on sample AR2–15. 52

Figure 22: Results of the uniaxial compression test on sample AR2–16. 53

Appendix C: Scioto County Fracture Gradient Calculations

The following section contains depictions of the logs and step by step calculations that factored into calculating the fracture gradient at the Scioto County Aristech Well.

Figure 23: Depiction of the deviation of the Scioto County Aristech Well p–wave curve from the normal compressional trend. Slower travel times (deviation to the right) represents reservoir overpressuring. 55

Cincinnati Group

Figure 24: Density log for the Scioto County Aristech Well. 56

Cincinnati Group

Figure 25: Reservoir fluid pressure gradient for the Scioto County Aristech Well, calculated from density and sonic logs, using the method of Hottman and Johnson (1965). 57

Cincinnati Group

Figure 26: Reservoir fluid pressure in pounds per square inch for the Scioto County Aristech Well. 58

Cincinnati Group

Figure 27: Fracture gradient for the Scioto County Aristech Well, calculated from the reservoir pressure, the overburden pressure, and Poisson’s ratio. Poisson’s ratios were determined from geomechanical tests (0.15 and 0.19), and compared to the typical values calculated from sonic logs in other wells. 59

Cincinnati Group

Figure 28: The pressure required to induce a fracture for the Scioto County Aristech Well. Again, three different Poisson’s ratios are compared. 60

Appendix D: Belmont County Fracture Gradient Calculations

The following section contains depictions of the logs and step by step calculations that factored into calculating the fracture gradient at the Belmont County well.

Cincinnati Group

Figure 29: Dipole sonic log, Belmont Co. Well. DTCO and DTSM curves, traveltime versus depth.

Cincinnati Group

Figure 30: Depiction of the deviation of the p–wave curve from the compressional trend in the Belmont County well. This deviation is proportional to the reservoir overpressuring. 63

Cincinnati Group

Figure 31: Density Log from the Belmont County well. Measurements are missing for a large portion of the log, but this does not affect the Cincinnati Group.

Cincinnati Group

Figure 32: Reservoir fluid pressure gradient, calculated from deviation of DTCO log from normal compression trend for the Belmont County well. 65

Cincinnati Group

Figure 33: Reservoir fluid pressure for the Belmont County well. 66

Cincinnati Group

Figure 34: Poisson’s ratio, calculated from DTCO and DTSM logs from the Belmont County well, according to method from Zhang and Bentley, 2005. 67

Cincinnati Group

Figure 35: Fracture gradient, calculated from the overburden pressure, the reservoir pressure, and Poisson’s ratio from the Belmont County well. 68

Cincinnati Group

Figure 36: Pressure required to produce a fracture at a given depth in the Belmont County well. 69

Appendix E: Gallia County Fracture Gradient Calculations

The following section contains depictions of the logs and step by step calculations that factored into calculating the fracture gradient at the Belmont County well.

Cincinnati Group

Figure 37: Dipole sonic logs, Gallia Co. Well. DTCO and DTSM curves, traveltime versus depth. 71

Cincinnati Group

Figure 38: Depiction of the deviation of the DTCO curve from the compressional trend in the Gallia County well. This deviation is proportional to the reservoir overpressuring. 72

Cincinnati Group

Figure 39: Reservoir fluid pressure for the Gallia County well. 73

Cincinnati Group

Figure 40: Reservoir fluid pressure gradient, calculated from deviation of DTCO log from normal compression trend in the Gallia County well. 74

Cincinnati Group

Figure 41: Density Log from the Gallia County well. 75

Cincinnati Group

Figure 42: Poisson’s ratio, calculated from DTCO and DTSM logs from the Gallia County well, according to method from Zhang and Bentley (2005). 76

Cincinnati Group

Figure 43: Fracture gradient, calculated from the overburden pressure, the reservoir pressure, and Poisson’s ratio from the Gallia County well. 77

Cincinnati Group

Figure 44: Pressure required to produce a fracture at a given depth in the Gallia County well. 78