reading

Contents

Cover

Title page

Copyright page

Dedication

Preface

List of Contributors

An Introduction to Hydraulic Fracturing

Chapter 1: Environmental Impact – Reality and Myth and Nero Did Not Fiddle While Rome Burned

1.1 The Tower of Babel and How it Could be the Cause of Much of the Fracking Debate

Chapter 2: Production Development

Chapter 3: Fractures: Their Orientation and Length

3.1 Fracture Orientation
3.2 Fracture Length/ Height

Chapter 4: Casing and Cementing

4.1 Blowouts
4.2 Surface Blowouts
4.3 Subsurface Blowouts
4.4 Horizontal Drilling
4.5 Fracturing and the Groundwater Debate

Chapter 5: Pre-Drill Assessments

5.1 Basis of Design

Chapter 6: Well Construction

6.1 Drilling
6.2 Completion

Chapter 7: Well Operations

7.1 Well Plug and Abandonment “P&A”
7.2 Considerations

Chapter 8: Failure and Contamination Reduction

8.1 Conduct Environmental Sampling Before and During Operations
8.2 Disclose the Chemicals Being Used in Fracking Operations
8.3 Ensure that Wellbore Casings are Properly Designed and Constructed
8.4 Eliminate Venting and Work Toward Green Completions
8.5 Prevent Flowback Spillage/Leaks
8.6 Dispose/Recycle Flowback Properly
8.7 Minimize Noise and Dust
8.8 Protect Workers and Drivers
8.9 Communicate and Engage
8.10 Record and Document

Chapter 9: Frack Fluids and Composition

9.1 Uses and Needs for Frack Fluids
9.2 Common Fracturing Additives
9.3 Typical Percentages of Commonly Used Additives
9.4 Proppants
9.5 Silica Sand
9.6 Resin Coated Proppant
9.7 Manufactured Ceramics Proppants
9.8 Additional Types
9.9 Slickwater

Chapter 10: So Where Do the Frack Fluids Go?

Chapter 11: Common Objections to Drilling Operations

11.1 Noise
11.2 Changes in Landscape and Beauty of Surroundings
11.3 Increased Traffic
11.4 Subsurface Contamination of Ground Water
11.5 Impacts on Water Wells
11.6 Water Analysis
11.7 Types of Methane and What They Show Us
11.8 Biogenic
11.9 Thermogenic
11.10 Possible Causes of Methane in Water Wells
11.11 Surface Water and Soil Impacts
11.12 Spill Preparation and Documentation
11.13 Other Surface Impacts
11.14 Land Use Permitting
11.15 Water Usage and Management
11.16 Flowback Water
11.17 Produced Water
11.18 Flowback and Produced Water Management
11.19 Geological Shifts
11.20 Induced Seismic Event
11.21 Wastewater Disposal Wells
11.22 Site Remediation
11.23 Regulatory Oversight
11.24 Federal Level Oversight
11.25 State Level Oversight
11.26 Municipal Level Oversight
11.27 Examples of Legislation and Regulations
11.28 Frack Fluid Makeup Reporting
11.29 FracFocus
11.30 Atmospheric Emissions

Chapter 12: Air Emissions Controls

12.1 Common Sources of Air Emissions
12.2 Fugitive Air Emissions
12.3 Silica Dust Exposure
12.4 Stationary Sources
12.5 The Clean Air Act
12.6 Regulated Pollutants
12.7 NAAQS Criteria Pollutants
12.8 Attainment Versus Non-attainment
12.9 Types of Federal Regulations
12.10 MACT/NESHAP HAPs
12.11 NSPS Regulations: 40 CFR Part 60
12.12 NSPS Subpart OOOO
12.13 Facilities/Activities Affected by NSPS OOOO
12.14 Other Types of Federal NSPS and NESHAP/MACT Regulations
12.15 NSPS Subpart IIII
12.16 NSPS Subpart JJJJ
12.17 NSPS Subpart KKK
12.18 MACT Subpart HH and Subpart HHH
12.19 MACT Subpart ZZZZ
12.20 Construction and Operating New Source Review Permits
12.21 Title V Permits

Chapter 13: Chemicals and Products on Locations

13.1 Material Safety Data Sheets (MSDS)
13.2 Contents of an MSDS
13.3 Product Identification
13.4 Hazardous Ingredients of Mixtures
13.5 Physical Data
13.6 Fire and Explosion Hazard Data
13.7 Health Hazard Data
13.8 Emergency and First Aid Procedures
13.9 Reactivity Data
13.10 Spill, Leak, and Disposal Procedures
13.11 Personal Protection Information
13.12 HCS 2012 Safety Data Sheets (SDS)

Chapter 14: Public Perception, the Media, and the Facts

14.1 Regulation or Policy Topics: Media Coverage and Public Perception

Chapter 15: Notes from the Field

15.1 Going Forward

Chapter 16: Migration of Hydrocarbon Gases

16.1 Introduction
16.2 Geochemical Exploration for Petroleum
16.3 Primary and Secondary Migration of Hydrocarbons
16.4 Origin of Migrating Hydrocarbon Gases
16.5 Driving Force of Gas Movement
16.6 Types of Gas Migration
16.7 Paths of Gas Migration Associated with Oilwells
16.8 Wells Leaking Due to Cementing Failure
16.9 Environmental Hazards of Gas Migration
16.10 Migration of Gas from Petroleum Wellbores
16.11 Case Histories of Gas Migration Problems
16.12 Conclusions
References and Bibliography

Chapter 17: Subsidence as a Result of Gas/Oil/Water Production

17.1 Introduction
17.2 Theoretical Compaction Models
17.3 Theoretical Modeling of Compaction
17.4 Subsidence Over Oilfields
17.5 Case Studies of Subsidence over Hydrocarbon Reservoirs
17.6 Concluding Remarks
References and Bibliography

Chapter 18: Effect of Emission of CO₂ and CH₄ into the Atmosphere

18.1 Introduction
18.2 Historic Geologic Evidence
18.3 Adiabatic Theory
References

Chapter 19: Fracking in the USA

Appendix A: Chemicals Used in Fracking

Appendix B: State Agency Web Addresses

References

Bibliography

Index

End User License Agreement

List of Illustrations

Chapter 2

Figure 2.1 Comparison of Well Sites.

Chapter 9

Graph 9.1 Volumetric Percentages of Additives in Fracturing Fluids.
Figure 9.1 Proppant Size and Placement.
Figure 9.2 Proppant Shape.
Figure 9.3 Proppant Hardness.

Chapter 11

Chart 11.1 Water and Contaminates.

Chapter 16

Figure 16.1 Three processes can generate methane (CH₄), the main component in natural gas. Biogenic methane is produced by microorganisms during metabolism. Thermogenic methane forms when heat and pressure decompose deeply-buried organic matter. Chemical reactions deep inside the Earth can also generate methane. (Modified after Howell et al., 1993; in: Khilyuk et al., 2000, p. 46, figure 3.2.)
Figure 16.2 Frequency distribution of sum of methane gas homologs in different types of deposits. Figure based upon analysis and classification of 3500 worldwide reservoir gases. (Modified after Nikonov, 1971; in: Khilyuk et al., 2000, p. 47, figure 3.3.)
Figure 16.3 1907 U. S. Geological Survey drawing shows how oil from underground rock layers migrates upward to fill the La Brea pits. (Drawing from “Rancho La Brea, A Record of Pleistocene Life in California”.)
Figure 16.4 Relationship between the carbon isotope ratio and methane content [C₁/(C₁-C₂)] in gas. (Modified after Kaplan, 1994, p. 305, figure 13.)
Figure 16.5 Schematic diagram for the conversion of organic matter to methane and carbon dioxide. (Modified after Kaplan, 1994, p. 298, figure 2.)
Figure 16.6 The isotopic composition of gas as related to its origin. The left panel depicts the geologic context of the gas origin (e.g., shallow bacterial, thermogenic, etc.) The right panel shows the range of anticipated values for carbon (y-axis) and hydrogen (x-axis) isotopic composition of methane in different genetic types of gases. Inasmuch as the PDB and SNOW are enriched in the 13C and D in comparison to natural gases, the latter have negative δ¹³C and δD values. (Modified after Schoell et al., 1963, p. 338, figure 1.)
Figure 16.7 Biogeochemical process in a marsh. An idealized cross-setion of a deltaic organic-rich (reducing) sedimentary environment. The biogeochemical zones are a consequence of ecological succession. (After Claypool and Kaplan, 1994, p. 299, figure 4.)
Figure 16.8 δ¹³C values of selected materials. (Modified after Kaplan, 1994, p. 301, Figure 5.)
Figure 16.9 The δD values of selected materials. (Modified after Kaplan, 1994, p. 301, figure 5.)
Figure 16.10 Carbon and hydrogen isotopic compositions of methane from various sources. The heavy arrow points to a specific thermogenic gas sample. (After Schoell, 1980, figure 3.)
Figure 16.11 Number of commercial natural gas samples versus δ¹³C of methane. (After Jenden and Kaplan, 1989, Figure 1 and Jenden et al., 1993, p. 37, figure 1.)
Figure 16.12 Nitrogen concentration plotted versus carbon isotope ratio for samples from a gas storage field. (After Schoell et al., 1993, p. 342.)
Figure 16.13 Carbon and hydrogen isotopic compositions of gas samples from a gas storage field. The question mark is located where 6D is that of a native gas of different vintage (no measurement of this gas was available). (After Schoell et al., 1993, p. 342, figure 7.)
Figure 16.14 Compressibility factors for natural gases. (Modified from Brown et al., 1941; in: Natural Gasoline Supply Men’s Association, 1957, and Natural Gas Processors Suppliers Association, 1981, figure 16.3, p. 16.8.)
Figure 16.15 Methane compressibility factor, Z, at low to high pressures. (Modified after Savidge, 2000, figure 1.)
Figure 16.16 Methane compressibility behavior example factors, Z, on constant temperature lines vs. low to moderate pressures. (Modified after Savidge, 2000, figure 3.)
Figure 16.17 Hydrogen gas compressibility factor, Z; low to high pressure range. (Modified after Savidge, 2000, figure 2.)
Figure 16.18 Approximate pseudo-critical pressure as a function of natural gas gravity. Specific gravity of air equals 1.0. Pressure is absolute (p_a = p_g + 14.7). (After NGSMA, 1957, figure 4, p. 103.)
Figure 16.19 Approximate pseudo-critical temperature for natural gases vs. gravity with respect to air. (After NGSMA, 1957, p 103, figure 5.)
Figure 16.20 Density of water with various concentrations of dissolved salts, °Be = Baume scale. (Modified after Baert et al., 1996.)
Figure 16.21 Interrelationship among density, temperature (°C) and salinity of water. D = Density of water at a particulatr temperature and salinity, (Modified after Classzone, www.classzone.com/books/earth_science/terc/content/.)
Figure 16.22 Comparison charts to aid visual estimation of porosity. (Circles after Terry and Chilingar, 1955; squares after Folk. 1951.)
Figure 16.23 Relationship between void ratio and porosity.
Figure 16.24 Several different ways of packing speres. (After Graton and Frazer, 1933.)
Figure 16.25 Triangle diagram of ternary mixtures (water, oil and gas) with lines of equal relative permeability in %: (a) to gas (as a fnction of water and oil saturation); (b) to oil (as a function of gas and water saturation). (After Leverett, 1940, courtesy of AIME.)
Figure 16.26 Composition of a three-phase flow through the porous media. (After Leverett and Lewis, 1940, courtesy of AIME.)
Figure 16.27 Example of relative permeabilities to oil and to water for polar oil + alkaline water (curves 1 and 1’) and for polar oil + hard water (curves 2 and 2’). (Modified after Babalyan, 1956, p. 148.)
Figure 16.28 Solubility of methane in water at various pressures and temperature. (Modified after www.ipt.ntnu.no/jsg/undervisning/gas/abstracts/vibeke.xhtmll; after Bonham, 1978.)
Figure 16.29 Schematic diagram of steady-state diffusion from the gas pool to the surface. C = concentration of gas in water. (Modified after Gurevich et al., 1993, p. 224.)
Figure 16.30 Schematic diagram of gas bubble migrating upward. (After guevich et al., 1963, figure 3, p. 226.)
Figure 16.31 Gas bubble (or globule: bubble is smaller than globule) floating up through water in a channel where the diameter of the bubble or globule is smaller than that of the channel. W_s = weight of bubble or globule, Β = buoyant force, D = friction drag force and v = upward velocity of the bubble or globule. (After Khilyuk et al., 2000, figure 17.5, p. 261.)
Figure 16.32 Schematic diagram of the pressure distribution in a gas-filled wellbore and in a surrounding water-saturated formation. Arrows indicate potential escape paths of gas through corrosion holes in the casing. P_w = water pressure gradient. (Modified after Gurevich et al., 1993, Figure 6, p. 230.)
Figure 16.33 The number of oil and gas wells drilled within central provinces of Canada and central U. S. states: Colorado, Kansas, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Utah and Wyoming. (Modified after Allread et al., 2015, 348:401.)
Figure 16.34 Schematic diagram showing potential migration paths for gas from the reservoir to the secondary collection zones and then to the surface. The arrows show several of the various potential paths of gas migration. (After Gurevich et al., 1993, figure 17.)
Figure 16.35 Example of several sources for gas leaks for a well. (Modified after Bacu and Watson, 2000.)
Figure 16.36 Schematic of drill bit-tooth striking bottom of the drill-hole. The tooth of the bit in figure (a) strikes the rock with a force greater than the strength of the rock and chips out a piece of rock and also creates induction fractures. (b) WOB refers to the weight of the rock on the bit which induces fractures in the formation. (Modified after Aadnoy, 1990.)
Figure 16.37 Schematic cross-sections of borehole breakout and drilling-induced fracture (DIF; figure adapted from Hillis and Reynolds, 2000). Borehole breakouts form when the circumferential stress around the wellbore exceeds the compressive rock strength and, thus, are orientated parallel to the minimum horizontal stress (σ_H). DIF’s form when the circumferential stress exceeds the tensile strength of the well bore wal and are thus oriented parallel to the maximum horizontal stress σ_H. (Modified after Tingay a et al., 2008, figure 1.)
Figure 2.38 Schematic showing radial stresses about a cemented wellbore and casing. Where σ_r = radial stress; P_o = pore pressure. (Modified after Dusseault et al., 2000, figure 2.)
Figure 2.39 A fracture driven by pressure in a cement sheath due to gradient differences. P_o = pore pressure driving the fracture. (Modified after Dusseault et al., 2000, figure 3.)
Figure 2.40 A generated fracture in a cased cemented oilwell approaching the surface. Shown in black, beginning in the gas zone where pore pressure exceeds rock strength and then propagates toward the surface. P_o = pore pressure driving the fracture, σ_r, = stress at which rock ruptures, σ_h = stress at hydrostatic pressure, σ_v = maximum stress pressure in microannulus. (Modified after Dusseault et al., 2000, figure 4.)
Figure 16.41 Schematics illustrating the effect of various mechanical problems resulting from improper placement of cement in wellbores. (Modified after Ravi et al., 2002 and Newhall, 2006.)
Figure 16.42 Schematic illustrating the different ways gas bubbles (light gray) can migrate through cement prior to its setting (dark gray) that can lead to channeling. (Modified after Bonett and Pafitis, 1996, p. 39.)
Figure 16.43 Schematics illustrating the effect of various mechanical problems resulting from improper placement of cement in well bores. Arrows indicate direction of fluid flow (gas/liquid). (Modified after Bonett and Pafitis, 1996, figure 1, p. 37.)
Figure 16.44 Benzene concentrations versus API gravity for 61 crude oils and 14 condensates. (Note: API gravity data were unavailable for eight crude oils). Modified after Rixey, 2001.)
Figure 16.45 Ternary diagram showing the class of composition of the World’s crude oils. (Modified after Kamali et al., 2012.)
Figure 16.46 API gravity of oil vs density and classification of oil based on API gravity.
Figure 16.47 Ternary diagram showing the class composition of crude oils. (Modified after Tissot and Welte, 1978.)
Figure 16.48 Gas leak rate for various maximum reservoir pressures for the Leroy Gas Storage Project. (Modified after Tek, 1987, figure 11.16.)
Figure 16.49 Inglewood Oilfield, CA; contours on Vickers-Machado zone. (After California Division of Oil and Gas, 1961, p. 576.)
Figure 16.50 Los Angeles Oilfield; contours on top of the 1st Oil Sand. Productive area is shaded. (After California Division of Oil and Gas, 1961, p. 598.)
Figure 16.51 Montebello Oilfield; contours on top of the 8th zone. (After California Division of Oil and Gas, 1961, p. 606.)
Figure 16.52 Playa Del Rey Oilfield with contours on top of schist conglomerate. (After California Division of Oil and Gas, 1963, p. 634.)
Figure 16.53 Playa del Rey Oilfield showing location of oil-producing areas and gas storage reservoir. (In: Chilingar and Endres, 2006, figure 4.)
Figure 16.54 The cross-section and structure of the Salt Lake Oilfield. (After California Division of Oil and Gas, 1961, p. 652.)
Figure 16.55 Carbon isotope fingerprinting of migrating gas leaking from a shallow Salt Lake Oilfield. (After Schoell et al., 1993, p. 7, figure 8.)
Figure 16.56 Structure and cross-section of the Santa Fe Springs Oilfield. Contours on the top of the Bell Zone. After California Dvision of Oil and Gas. 1961, p. 662.)
Figure 16.57 Contours on top of Cascade zone and structure for the Castaic Hills Oilfield, CA. (After California Division of Oil and Gas, 1974.)
Figure 16.58 Contours on top of Wayside A Sand and Gabriel Sand along with structure for the Honor Rancho Oilfield. (After California Division of Oil and Gas, 1974.)
Figure 16.59 Contours on top of the Yule Sand and structure of the Tapia Oilfield, CA. (After California Division of Oil and Gas, 1974.)
Figure 16.60 Physical relationship of the Castaic Hills, Honor Rancho and Tapia Oilfields, CA. Arrows show the prevailing direction of gas migration. (After California Division of Oil and Gas, 1974.)
Figure 16.61 Surface map illustrating road (solid lines) and well locations for the Leroy Gas Storage Project, WY. (After Tek, 1987, figure 11.7, p. 316.)
Figure 16.62 Lithologic cross-section and stratigraphic sequence of the Leroy Gas Storage Project, WY. (After Tek, 1987, figure 11.8, p. 317.)
Figure 16.63 Schematic representation of gas leakage from the Leroy Gas Storage Project. c_p = performance coefficient for leak, MMCF/D/psi², P_o = maximum storage pressure, psia. After Tek, 1987, figure 11.12, p. 323.

Chapter 17

Figure 17.1 Simplified schematic representation of clay compaction (concept after Terzaghi and Peck, 1948, p. 84; In: Holtman and Johnson, 1965, p. 718.). σ = grain-to-grain bearing strength; S = axial component of total stress (overburden pressure); p = fluid pressure; and λ = ratio of the pore stress to total stress: σ = S – p. Stage A: overpressured system; water is not allowed to escape. Stage B: water is allowed to escape: springs carry part of the applied load. Stage C: compaction equilibrium; load is supported by the springs and the water (water pressure is simply hydrostatic). (Modified after Rieke and Chilingarian, p. 93, 1974.)
Figure 17.2 Illustration of load transfer owing to water-level drop or reduction in pore-water pressure in unconfined and confined aquifers. Geostatic, hydrostatic and intergranular pressure gradients are plotted assuming that solids and water have specific gravities of 2.7 and 1.0, respectively, and that porosity is equal to 35%. (Modified after Allen et al., 1971, figure 4, p. 285. Courtesy of Enciclopedia della Scienza e dell Tecnica, Mondadori.).
Figure 17.3 Relationship between void ratio and applied pressure for sand, silt and clay cores obtained at different depths from various areas. 1 = Corcoran Clay (depth of 425 ft); 2 = very loose sand; 3 = Corcoran Clay (depth of 735 ft); 4 = silt (depth of 1,345 ft); 5 = average Wilmington, California sands (depth of 2,000–4,000 ft); 6 = average Wilmington, California siltstones (depth of 2000–2,900 ft); 7 = sand from Maracaibo, Venezuela (depth of 3,000 ft); 8 = intermediate compacted sand; 9 = average Wilmington, California siltstone (depth of 3,000 ft); 10 = very compacted sand; 11 = average Wilmington, California siltstone (depth of 3,100–3,500 ft); 12 = clay from Maracaibo, Venezuela (depth of 3,104 ft); 13 & 14 = average Wilmington, California, siltstones (depth of 3,600–6,000 ft). (After Allen and Mayuga. 1969. In: Chilingarian et al., 1995, p. 187, figure 3.11.)
Figure 17.4 Relationship between void ratio and applied pressure for clay and shale. Curve 1 = undisturbed Boston Blue Clay; Curves 2,7 & 8 = clay cores from Venezuela (depths of 2,486 to 4769 ft); Curves 3 & 4 = compressed curves for plastic clays with liquid limits of 80 and 30% with a P. I. of 50 & 12, respectively (Skempton, 1953); Curve 5 = undisturbed shale (C11); and Curve 6 = undisturbed shale (C5). (After Roberts, 1969, figure 1, p. 369. In: Chilingarian et al., 1995, p. 188, figure 3.12.)
Figure 17.5 Relationship between void ratio and applied pressure for oilfield sands. Curve 1 = remolded(25.10); Curves 2 & 6 = remolded (M.I.T. Geol. Dept.); Curve 3 = undisturbed (1.1); Curve 4 = undisturbed (25.1); Curve 5 = remolded (25.13). (After Roberts, 1969, figure 4, p. 372. In: Chilingarian et al., 1995, figure 3.12, p. 183.)
Figure 17.6 Relationship between the porosity and depth of burial for shales and argillaceous sediments. Source: Curve I = Proshlyakov (1960); Curve 2 = Meade (1966); Curve 3 = Athy (1930); Curve 4 = Hosoi (1963); Curve 5 = Hedberg (1936) Curve 6 = Dickinson (1953); Curve 7 = Magara (1968); Curve 8 = Weller (1959); Curve 9 = Ham (1966); and Curve 10 = Foster and Whalen (1966). (After Rieke and Chilingarian, 1974, p. 42, figure 17.)
Figure 17.7 (a) Relationship between bulk density and depth for Oklahoma shales, (b) Relationship between porosity and depth for Oklahoma shales. (After Athy, 1930, Figures 2 and 3, pp 12 & 13. In: Rieke and Chilingarian, 1974, p. 37, figure 14. Courtesy of the American Association of Petroleum Geologists.)
Figure 17.8 Relationship between porosity, depth of burial and overburden pressure. Ν = unit of force (Newton) = 102 g-force = 10⁵ dynes. (After Weller and Vassoevich, in: Kartsev et al., 1969, in: Rieke and Chilingarian, 1974, p. 43, figure 18.)
Figure 17.9 Schematic representation of clay compaction, porosity and permeability relationships and creation of abnormally high formation fluid pressures. Where k = permeability; φ = porosity; t = time; p = pore pressure; γ_w = specific weight of water; h = height to which fluid will rise in the tubes; this represents the pressure head (Ρ/γ_w); W = water and G = gas. (Modified after Katz and Ibrahim, 1971, figure 12, courtesy of Soc. Pet. Eng., in: Rieke and Chilingarian, 1974, p. 319, figure 170.)
Figure 17.10 Subsidence of Long Beach, CA, area between 1928 and 1962 of the Wilmington Oilfield, CA. The subsidence shown in the upper right is due to fluid withdrawal from the Long Beach (Signal Hill) oilfield, whereas that in the foreground is due to fluid withdrawal from the Wilmington oilfield. Lines of equal subsidence are in feet (–2’, –4’, –6’, –10’, –14’, –22’, –27’ and –29’). (Courtesy of City of Long Beach Department of Oil Properties, CA.; http://www.lonbeach.ov/lba/about-us/oil/subsidence/)
Figure 17.11 Schematic diagram of compressive and tensile stress distribution in subsiding formation due to fluid withdrawal. (Modified after Gurevich and Chilingarian. 1993, figure 1, p. 224.)
Figure 17.12 Schematic of casing count surveys of a typical well in the Wilmington Oilfield. (Modified after Poland ad Davis, 1969; in: Gurevich and Chilingarian, 1993, figure 2, p. 244.)
Figure 17.13 Locations of epicenters and slip planes of subsidence earthquakes, Wilmington Oilfield, Long Beach, CA. (After Kosloff et al., 1980 figure 3, p. 245. In: Gurevich and Chilingarian, 1993.)
Figure 17.14 Deformation pattern of strata above longwall extraction with strong overburden (physical model). (After Whittaker and Reddish, 1989; in: Gurevich and Chilingarian, 1993, figure 4, p. 254.)
Figure 17.15 Total subsidence in Wilmington Oilfield area in 1954. (In: Chilingarian et al., 1995, p. 296, figure 6.8.)
Figure 17.16 Uniaxial compaction coefficient c_m (vertical axes) for unconsolidated and semi-consolidated sandstone reservoirs. The effective vertical stresses σ₁. range from 100 to 200 kg/cm², correspondin to a depth of burial of 1000 m and σ₂ = 300 to 600 kg/cm² for a depth of burial of 3000 m for normal pressure reservoirs. (Modified after Geertsma, 1973, figures 1 & 2. 736 & 738.)
Figure 17.17 Schematic diagram of system relationships among production of fluids, compaction, subsidence, and seismic activity. (After Chilingarian et al., 1995, figure D-1, p. 461.)
Figure 17.18 Subsidence profiles across the Picacho Fault, AZ. (Modified after Holzer and Thatcher, 1979; in: Gurevich and Chilingarian, 1993, figure 6, p. 247.)
Figure 17.19 Trench logs of the Pixly fissure, San Joaquin Valley, CA. I I 21 24 (Modified after Guacci, 1979; in: Gurevich and Chilingarian, 1993, figure 5, p. 246.)
Figure 17.20 Distribution of oilfields in the Los Angeles Basin, CA. (After California Division of Oil and Gas, 1961.)
Figure 17.21 Structure and contour map of the Inglewood Oilfield showing location of the Newport Fault. Contours on the Vickers-Machado zone. (After California Division of Oil and Gas, 1961, p. 561.)
Figure 17.22 Horizontal movements and subsidence rates in the area of the Baldwin Hills Dam. (Modified after Lee, 1976, p. 301, figure 1.)
Figure 17.23 Subsidence of benchmarks, Baldwin Hills Dam area, Los Angeles, CA. (After California Department of Water Resources, Baldwin Hills Reservoir, Apr. 1964, figure 2.5, p. 8.)
Figure 17.24 Los Angeles Oilfield, contours on top of 1st Oil Sand. Productive area is shaded. (After California Division of Oil and Gas, 1961, p. 598.)
Figure 17.25 Playa Del Rey Oilfield with contours on top of the Franciscan Schist. (After California Division of Oil and Gas, 1963, p. 634.)
Figure 17.26 Subsidence in the Playa Del Rey Oilfield. Vertical movement in feet occuring between 1937 to 1970. (After California Division of Oil and Gas, 1961.)
Figure 17.27 Torrance Oilfield showing the geologic structure on the top of Main Zone. The Redondo Beach Oilfield is an extened portion of the Torrance Oilfield as shown above. (After the California Division of Oil and Gas, 1961, p.674.)
Figure 17.28 Changes in the North Redondo Beach breakwater elevation during the period of 1955 to 1980. (Data obtained from U.S. Army Corps of Engineers; in: Robertson et al., 2012.)
Figure 17.29 The cross-section and geologic structure of the Salt Lake Oilfield. (After California Division of Oil and Gas, 1961, p. 652.)
Figure 17.30 Structure and cross-section of the Santa Fe Springs Oilfield. Conturs on to of the Bell Zone. (After California Division of Oil and Gas, 1961, p. 662.)
Figure 17.31 Structure and cross-section of the Wilmington Oilfield. Contours on top of the Ranger Zone. (After California Division of Oil and Gas, 1961, pp. 684 & 685.)
Figure 17.32 Northwest-southwest cross-section of the Wilmington Oilfield showing profile of subsidence bowl on top of the Wilmington anticline. (After Colazas, 1971; in: Chilingarian et al., 1995, p. 297, figure 6.10.)
Figure 17.33 Wilmingtion Oilfield subsidence unit: 1973 to 1974 subsidence in feet. (After California Division of Oil and Gas, Sixth Annual Report.)
Figure 17.34 Composite electric log showing stratigraphic sections and markers of the Wilmington Oilfield. (After Colazas, 1971; in: Chilingarian et al., 1995, p. 287, figure 6.2.)
Figure 17.35 Geologic section along axis of Wilmington Anticline showing approximate water/oil limits. (After Mayuga, 1970; in: Chilingarian et al., 1995, p. 289, figure 6.3.)
Figure 17.36 Curve showing cumulative total production versus cumulative total subsidence of the Wilmington Oilfield, CA (After Mayuga and Allen, 1998.)
Figure 17.37 Historical oil production, water injection and subsidence in the Wilmington Oilfield, CA. (After Mayuga and Allen, 1998.)
Figure 17.38 Diagrammatic shale-water flow to low-pressure permeable sands. (After Colazas and Strehle, 1995; in: Chilingarian et al., 1995.)
Figure 17.39 Fractional compaction of clay layers of various thickness following instantaneous drop in reservoir pressure. (After van der Knaap and van der VIis, 1966; in: Colazas and Sterhle, 1995, figure 6.12, p. 300.)
Figure 17.40 Subsidence of the Earth’s surface at the Yastrebin Oilfield (A) and Braguny Oilfield (B). Solid circles indicate borehole locations; numbers between parentheses are Δh_calc, values in m. In the case of open circles, Δh_mean values are measured. (After Dobrynin and Serebryakov, 1989, figure 124, p. 282; also in: Serebrybryakov and Chilingar, 2000, figure 2, p. 425.)
Figure 17.41 Abnormally low formation pressure in the borehole Number 83, Braguny Oilfield, Russia. Lithology: 1 = shale; 2 = sandstone; 3 = abnormally low pressure zones; 4 = curve for normaly compacted clays; 5 = resistivity of shales (ohm-m). (After Dobrynin and Serebraykov, 1989, Figure 122, p. 272; also in: Serebraykov and Chilingarian, 2000, figure 1, p. 413.)
Figure 17.42 Relationship between Δh/h and formation pressure drop due to production (Δp = p_i – p_f) in MPA^–1; Δh = subsidence, m; h = formation thickness, m; p_i; = initial formation pressure, MPa^–1; p_f = final formation pressure after a certain amount of production, MPa^–1; ϕ = initial porosity = 15.9%; and numbers on curve are β_p = weighted Pore compressibility. (After Dobryin and Serebryakov, 1989; in: Serebryakov and Chilingarian. 2000. figure 3, p. 415.)
Figure 17.43 Bolivar Coastal Fields (BCF). (After Finol and Sancevic, 1995; in: Chilingarian et al., 1955, p. 341.)
Figure 17.44 Stratigraphic section of Bolivar Coastal Fields. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 343, figure 7.30.)
Figure 17.45 A northeast-southwest crosssection through the Bolivar Coastal Fields (BCF). After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 344, figure 7.4.)
Figure 17.46 Main leveling network and subsidence contours. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 350, figure 7.8.)
Figure 17.47 Cumulative subsidence of bench mark (BM) AB (see Figure 3.47 for location). (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 350, figure 7.9.)
Figure 17.48 Progressive raising of the dike with respect to time. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 348, figure 7.5.)
Figure 17.49 Subsidence history and prediction along the Bachaquero dike. (After Finol and Sancevic, 1995; in: Chilingarian et al, 1995, p. 349, figure. 7.6.)
Figure 17.50 Subsidence history and prediction along the Lagunillas dike. (Modified after Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p.349, figure 7.7.)
Figure 17.51 Cummulative subsidence of bench mark (BM) 215 B (see Figure 3.46 for location). (After Finol and Sancevic, 1995; in: Chilingarian et al.,1995, p. 351, figure 7.9.)
Figure 17.52 The relative contributions of various drive mechanisms, Bachaquero Reseervoir, Venezuela. Reservoir volumes of free gas, compaction, and invaded water (percent of initial pore volume). (After Merle et al., 1975; in: Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 355, figure 7.13.)
Figure 17.53 Simplified view of the Po-Veneto Plain. The triangles indicate main hydrocarbon reservoirs. After Btrighenti et al., 1995; in: Chilingarian et al., 1995.)
Figure 17.54 Land subsidence in the Po Delta in the period of 1951 to 1962 expressed in cm. The grey area indicates the area in which in 1960 the withdrawal of gas-bearihg water was discontinued. (After Borgia et al., 1985a; in Chilingarian et al., 1995, p. 239, figure 5.18.)
Figure 17.55 Schematic cross-section of the Po Basin. (After Brighenti et al., 1995; in Chilingarian et al., 1995, p. 239, figure 5.19.)
Figure 17.56 Average sinking rate (solid line) and annual gas production (dashed line) in the period of 1956–1961 in the Po Delta. (After Borgia et al., 1985a; in: Chilingarian et al., 1995, p. 243, figure 5.22.)
Figure 17.57 Depth variation of a nearly 700-m deep well located in the Po Delta, measured by means of a moveable extensometer. h = depth (m), t = time (years). (After Borgia et al., 1982; in: Chilingarian et al., 1995, p. 244, figure 5.23.)
Figure 17.58 Soil-sinking charts of some significant bench marks updated in 1978; heights are expressed in meters and refer to sea level. (Brighenti et al., 1995; in: Chilingarian et al., 1995, figure 5.25, p. 246.)
Figure 17.59 Examples of variation in the cross-section of the Po River which occurred near Polesella, Rovigo Province, Italy, with time. (After Bondesan and Bizzari, in: Brighenti et al., 1995; in: Chilingarian et al., 1995, figure 5.26, p. 247.)
Figure 17.60 Location map of the North Sea oilfields. (After the Petroleum Resources of the North Sea Energy Administration; in: Chilingarian et al., 1995, p. 324, figure 8.1.)
Figure 17.61 Promising structures within the major sedimentary basin that runs north to south through the North Sea, based upon seismic data. Ekofisk production is from 700 ft of lower Tertiary limestone as illustrated in the basin cross-section on a line from Norway to England. (After Snyder, 1971; in: Chilingarian et al., 1995, p. 376, figure 8.2.)
Figure 17.62 Representative porosity log from an Ekofisk well. (After Boade et al., 1989; in: Chilingarian et al., 1995, p. 378, figure 8.3.)

Chapter 18

Figure 18.1 Schematic showing the relationship between average global temperature (solid line) and atmospheric carbon dioxide (dashed line) over geologic time. The late Carboniferous to Early Permian Period (315 mya to 270 mya) is the only time in the last 600-million years when both the atmospheric carbon dioxide content and temperatures were as low as they are today. (Modified after Hieb, M, 2009, in: Climate and the Carboniferous Period, http//www.geocraft.com/MVFossils/Carboniferous_climate.xhtmll., data for temperature obtained from Scotes and CO₂ after Berner, 2001.)
Figure 18.2 Deviation of Earth’s lower atmospheric temperature from 2000 A.D. for the last 400,000 years. (Modified after Dillon, 2015. Data for temperature sources: Satellite stratosphere data (2000–1979); Southern hemisphere ground temp. data (1979–1871); Vostok ice core data (1871–422 k B.P.).)
Figure 18.3 Running centered 13-month average of UAH satellite-based temperature of the global lower atmosphere (version 6.0) from 1979 to June 2015. (Modified after Bastasch, 2015.)
Figure 18.4 A reconstruction of temperature deviation, to the 1961–1900 mean for the Earth’s northern hemisphere during the last two millennia. This shows that the current warm period is not exceptional. (Modified after Geografiska Annaler, 2010.)
Figure 18.5 Schematic showing relationship between the CO₂ content in the atmosphere (dashed line) and the volcanic activity on Earth (solid line). (Modified after Archer, 2010.)
Figure 18.6 800,000-year record of atmospheric CO₂ content and a reconstruction of temperature from Antarctic ice cores. Temperature values in solid line and percent CO₂ in atmosphere in dashed line. (Modified after Shakun, 2012.)
Figure 18.7 Schematic showing relationship between global air temperature vs. human CO₂ emissions from 16 AD to 2010. (Evans, 2010, states that these emission figures are not perfect because they omit some minor causes, e.g., deforestation; however, these are relatively minor). Evans also noted that the temperatures from 1850 to 1980 are suspect because they come from land-thermometers. (Modified after Evans. 2010.)
Figure 18.8 Pathways of carbon in the carbon cycle showing storage areas of carbon, e.g., ocean, atmosphere, vegetation, and rock. The ocean is one of the largest storage areas of carbon (After Earth Labs, http://serc.carleton.edu/eslabs/carbon/index.xhtmll).
Figure 18.9 Relationship between the temperature and the solubility of CO₂ in water. (Data obtained from Wallace, 2009.)
Figure 18.10 Sources of Carbon looking at the rock cycle showing outgassing from the Earth’s interior at Midocean ridges, hotspot volcanoes and subductiuon-related volcanic (breakdown of carbonates, etc. volcanism. (After http//www.columbia.edu/-v”d1/carbon.xhtml).
Figure 18.11 Global volcanism overtime by decade from 1850 to 2010. There has been a general increase in volcanism over the past 100 years. (Modified after http://informacaoincorrecta.blogspot.com/2011/08/porque-nibiru-nao-existe.xhtmll)
Figure 18.12 Averaged temperature distributions in the Earth’s troposphere using Eq. 4.1: Model 1 - Earth’s troposphere with a nitrogen-oxygen atmosphere; Model 2 - Earth’s atmosphere composed totally of carbon dioxide; and Model 3 - Earth’s atmosphere composed totally of methane. All other parameters of models 2 and 3 are the same as in model 1. (After Chilingar et al., 2009, p. 1210, figure 2.)
Figure 18.13 Distribution of experimentally determined temperature within the Earth’s troposphere and stratosphere (curve 4: Bachinsky et al., 1951) and within the Venetian troposphere (curves 1 and 2: Venus, 1989) as compared to the theoretical distributions (curves 4 and 3). Constructed in accordance with the adiabatic theory of the greenhouse effect. Temperatures are in Kelvin. (After Chilingar et al., 2009.)
Figure 18.14 Averaged temperature distributions in the Venetian troposphere based on Eq. 4.1: (curve 1) Venus’s carbon dioxide troposphere and (curve 2) the temperature distribution for a hypothetical model of the nitrogen-oxygen troposphere for Venus with all other conditions being equal. (After Chilingar et al., 2009, p. 1210, figure 3.)
Figure 18.15 Solar irradiance (W/m²) and CO₂ concentrations in atmosphere (p-pmv) in Northern Hemisphere (solid dots). (Modified after Hoyt and Schatten, 1997.)

List of Tables

Chapter 1

Table 3.1 Well Comparisons.

Chapter 11

Table 11.1 Water use comparison.

Chapter 14

Table 14.1 Tone of media coverage.
Table 14.2 Fracking Incidents.

Chapter 16

Table 16.1 Typical composition of natural gases expressed in mole % (or volume %). (In: Chilingar et al., 1969, table 1, p.89.)
Table 16.2 Physical constants of light hydrocarbons and other components associated with natural gas. (Data abstracted from Natural Gas Processors Suppliers Association, 1981.)
Table 16.3 Types of chemical reaction leading to methane formation. (Modified after Kaplan, 1004, figure 1, p. 298.)
Table 16.4 Ranges of carbon and deuterium isotope ratios for methane derived from different origins. (After Kaplan, 1994, table 2, p. 301.)
Table 16.5 Time period for gas migration rate and rate of loss to the surface for vertical steady-state diffusion from a depth of 1740 m. (Modified after Smith et al., 1971; in Hunt, 1979, table 9–2. p. 427.)

Chapter 17

Table 17.1 Subsidence found in various cities as a result of fluid withdrawal. (Modified after Nelson, 2015.)
Table 17.2 Geologic formation data, oil producing zones and summary of reservoir data for the various zones of the Wilmington Oilfield, CA. (After Colazas, 1971; in: Chilingarian et al., 1995, table 6.1, p. 288.)
Table 17.3 Depth and thickness of Wilmington Oilfield oil zones. (After Colazas, 1971; in: Chilingarian et al., 1995, table 6–11, p. 291.)
Table 17.4 Values of determined on the basis of repeated leveling for the Braguny Oilfield, Russia. (After Dobrynin and Serebryakov, 1989; in: Chilingar et al., 2002, table 13.1, p. 356.)
Table 17.5 Subsidence of the Earth’s surface (Δh) at the Tersk-Sunzhen petroliferous area using . (After Dobrynin and Serebryakov, 1989; in: Chilingar et al., 2002, table 13.2, p. 357.)
Table 17.6 Ekofisk reservoir data. (After Snyder, 1971; in Chilingarian et al., 1995, table 8.1, p. 375.)

Appendix A

Table 1 Chemical Identity And Chemical/Physical Properties Of Acetaldehyde.
Table 2 Estimated 1986 United States End-Use Pattern of Acetaldehyde.
Table 3 Epa Offices And Contact Numbers For Information On Acetaldehyde.
Table 4 Other Federal Offices/Other Group Contact Numbers For Information On Acetaldehyde.

This edition first published 2018 by John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, USA
and Scrivener Publishing LLC, 100 Cummings Center, Suite 541J, Beverly, MA 01915, USA
© 2018 Scrivener Publishing LLC
For more information about Scrivener publications please visit www.scrivenerpublishing.com.

All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, except as permitted by law. Advice on how to obtain permission to reuse material from this title is available at http://www.wiley.com/go/permissions.

Wiley Global Headquarters
111 River Street, Hoboken, NJ 07030, USA

For details of our global editorial offices, customer services, and more information about Wiley products visit us at www.wiley.com.

Limit of Liability/Disclaimer of Warranty
While the publisher and authors have used their best efforts in preparing this work, they make no representations or warranties with respect to the accuracy or completeness of the contents of this work and specifically disclaim all warranties, including without limitation any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representatives, written sales materials, or promotional statements for this work. The fact that an organization, website, or product is referred to in this work as a citation and/or potential source of further information does not mean that the publisher and authors endorse the information or services the organization, website, or product may provide or recommendations it may make. This work is sold with the understanding that the publisher is not engaged in rendering professional services. The advice and strategies contained herein may not be suitable for your situation. You should consult with a specialist where appropriate. Neither the publisher nor authors shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages. Further, readers should be aware that websites listed in this work may have changed or disappeared between when this work was written and when it is read.

Library of Congress Cataloging-in-Publication Data

ISBN 978-1-119-36342-2

Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing