Contents

Cover

Title page

Copyright page

Dedication

Acknowledgments

Chapter 1: Environmental Concerns

1.1 Introduction
1.2 Evaluation Approach
1.3 Gas Migration
1.4 Underground Gas Storage Facilities
1.5 Subsidence
1.6 Emissions of Carbon Dioxide and Methane
1.7 Hydraulic Fracturing
1.8 Oil Shale
1.9 Corrosion
1.10 Scaling
1.11 Conclusion
References and Bibliography

Chapter 2: Migration of Hydrocarbon Gases

2.1 Introduction
2.2 Geochemical Exploration for Petroleum
2.3 Primary and Secondary Migration of Hydrocarbons
2.4 Origin of Migrating Hydrocarbon Gases
2.5 Driving Force of Gas Movement
2.6 Types of Gas Migration
2.7 Paths of Gas Migration Associated with Oilwells
2.8 Wells Leaking Due to Cementing Failure
2.9 Environmental Hazards of Gas Migration
2.10 Migration of Gas from Petroleum Wellbores
2.11 Case Histories of Gas Migration Problems
2.12 Conclusions
References and Bibliography

Chapter 3: Subsidence as a Result of Gas/Oil/Water Production

3.1 Introduction
3.2 Theoretical Compaction Models
3.3 Theoretical Modeling of Compaction
3.4 Subsidence Over Oilfields
3.5 Case Studies of Subsidence over Hydrocarbon Reservoirs
3.6 Concluding Remarks
References and Bibliography

Chapter 4: Effect of Emission of CO₂ and CH₄ into the Atmosphere

4.1 Introduction
4.2 Historic Geologic Evidence
4.3 Adiabatic Theory
References

Chapter 5: Fracking

5.1 Introduction
5.2 Studies Supporting Hydraulic Fracturing
5.3 Studies Opposing Hydraulic Fracturing
5.4 The Fracking Debate
5.5 Production
5.6 Fractures: Their Orientation and Length
5.7 Casing and Cementing
5.8 Blowouts
5.9 Horizontal Drilling
5.10 Fracturing and the Groundwater Contamination
5.11 Pre-Drill Assessment
5.12 Basis of Design
5.13 Well Construction
5.14 Summary
5.15 Failure and Contamination Reduction
5.16 Frack Fluids
5.17 Common Fracturing Additives
5.18 Typical Percentages of Commonly Used Additives
5.19 Chemicals Used in Fracking
5.20 Proppants
5.21 Slickwater
5.22 Direction of Flow of Frack Fluids
5.23 Subsurface Contamination of Groundwater
5.24 Spills
5.25 Other Surface Impacts
5.26 Land Use Permits
5.27 Water Usage and Management
5.28 Earthquakes
5.29 Induced Seismic Event
5.30 Wastewater Disposal Wells
5.31 Site Remediation
5.32 Examples of Legislation and Regulations
5.33 Frack Fluid Makeup Reporting
5.34 Atmospheric Emissions
5.35 Air Emissions Controls
5.36 Silica Dust
5.37 The Clean Air Act
5.38 Regulated Pollutants
5.39 Attainment versus Non-attainment
5.40 Types of Federal Regulations
5.41 MACT/NESHAP
5.42 NSPS Regulations: 40 CFR Part 60
5.43 Construction and Operating New Source Review Permits
5.44 Title V Permits
5.45 Chemicals and Products on Locations
5.46 Material Safety Data Sheets (MSDS)
5.47 Contents of an MSDS
5.48 Conclusion
State Agency Web Addresses
References
Bibliography

Chapter 6: Corrosion

6.1 Introduction
6.2 Definitions
6.3 Electrochemical Corrosion
6.4 Galvanic Series
6.5 Types of Corrosion
6.6 Classes of Corrosion
6.7 Stress-Induced Corrosion
6.8 Microbial Corrosion
6.9 Corrosion Related to Oilfield Production
6.10 Economics and Preventitive Methods
6.11 Corrosion Rate Measurement Units
References and Bibliography

Chapter 7: Scaling

7.1 Introduction
7.2 Sources of Scale
7.3 Formation of Scale
7.4 Hardness and Alkalinity
7.5 Common Oilfield Scale Scenarios
7.6 Prediction of Scale Formation
7.7 Solubility of Calcite, Dolomite, Magnesite and Their Mixtures
7.8 Scale Removal
7.9 Scale Inhibition
7.10 Conclusions
References and Bibliography

Appendix A

About the Authors

Author Index

Subject Index

End User License Agreement

List of Illustrations

Chapter 1

Figure 1.1 U.S. oil and natural gas proved reserves, 1973–2013. (After EIA, U.S.A., 2014, Figure 2.)
Figure 1.2 Effect of relative magnitude of principal stresses on fracture orientation. (After Fertl and Chilingarian, 1978, Figure A0-4, p. 301.).

Chapter 2

Figure 2.1 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 2.2 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 2.3 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 2.4 Relationship between the carbon isotope ratio and methane content [C₁/(C₁-C₂)] in gas. (Modified after Kaplan, 1994, p. 305, figure 13.)
Figure 2.5 Schematic diagram for the conversion of organic matter to methane and carbon dioxide. (Modified after Kaplan, 1994, p. 298, figure 2.)
Figure 2.6 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 2.7 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 2.8 δ¹³C values of selected materials. (Modified after Kaplan, 1994, p. 301, figure 5.)
Figure 2.9 The δD values of selected materials. (Modified after Kaplan, 1994, p. 301, figure 5.)
Figure 2.10 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 2.11 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 2.12 Nitrogen concentration plotted versus carbon isotope ratio for samples from a gas storage field. (After Schoell et al., 1993, p. 342.)
Figure 2.13 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 2.14 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 2.15 Methane compressibility factor, Z, at low to high pressures. (Modified after Savidge, 2000, figure 1.)
Figure 2.16 Methane compressibility behavior example factors, Z, on constant temperature lines vs. low to moderate pressures. (Modified after Savidge, 2000, figure 3.)
Figure 2.17 Hydrogen gas compressibility factor, Z; low to high pressure range. (Modified after Savidge, 2000, figure 2.)
Figure 2.18 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 2.19 Approximate pseudo-critical temperature for natural gases vs. gravity with respect to air. (After NGSMA, 1957, p 103, figure 5.)
Figure 2.20 Density of water with various concentrations of dissolved salts, °Be = Baume scale.
(Modified after Baert et al., 1996.)
Figure 2.21 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 2.22 Comparison charts to aid visual estimation of porosity. (Circles after Terry and Chilingar, 1955; squares after Folk. 1951.)
Figure 2.23 Relationship between void ratio and porosity.
Figure 2.24 Several different ways of packing speres. (After Graton and Frazer, 1933.)
Figure 2.25 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 2.26 Composition of a three-phase flow through the porous media. (After Leverett and Lewis, 1940, courtesy of AIME.)
Figure 2.27 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 2.28 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 2.29 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 2.30 Schematic diagram of gas bubble migrating upward. (After guevich et al., 1963, figure 3, p. 226.)
Figure 2.31 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, B = 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 2.32 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 2.33 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 2.34 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 2.35 Example of several sources for gas leaks for a well. (Modified after Bacu and Watson, 2000.)
Figure 2.36 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 2.37 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 2.41 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 2.42 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 2.43 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 2.44 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 2.45 Ternary diagram showing the class of composition of the World’s crude oils. (Modified after Kamali et al., 2012.)
Figure 2.46 API gravity of oil vs density and classification of oil based on API gravity.
Figure 2.47 Ternary diagram showing the class composition of crude oils. (Modified after Tissot and Welte, 1978.)
Figure 2.48 Gas leak rate for various maximum reservoir pressures for the Leroy Gas Storage Project. (Modified after Tek, 1987, figure 11.16.)
Figure 2.49 Inglewood Oilfield, CA; contours on Vickers-Machado zone. (After California Division of Oil and Gas, 1961, p. 576.)
Figure 2.50 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 2.51 Montebello Oilfield; contours on top of the 8th zone. (After California Division of Oil and Gas, 1961, p. 606.)
Figure 2.52 Playa Del Rey Oilfield with contours on top of schist conglomerate. (After California Division of Oil and Gas, 1963, p. 634.)
Figure 2.53 Playa del Rey Oilfield showing location of oil-producing areas and gas storage reservoir. (In: Chilingar and Endres, 2006, figure 4.)
Figure 2.54 The cross-section and structure of the Salt Lake Oilfield. (After California Division of Oil and Gas, 1961, p. 652.)
Figure 2.55 Carbon isotope fingerprinting of migrating gas leaking from a shallow Salt Lake Oilfield. (After Schoell et al., 1993, p. 7, figure 8.)
Figure 2.56 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 2.57 Contours on top of Cascade zone and structure for the Castaic Hills Oilfield, CA. (After California Division of Oil and Gas, 1974.)
Figure 2.58 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 2.59 Contours on top of the Yule Sand and structure of the Tapia Oilfield, CA. (After California Division of Oil and Gas, 1974.)
Figure 2.60 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 2.61 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 2.62 Lithologic cross-section and stratigraphic sequence of the Leroy Gas Storage Project, WY. (After Tek, 1987, figure 11.8, p. 317.)
Figure 2.63 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 3

Figure 3.1 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 3.2 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 3.3 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 3.4 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 3.5 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 3.6 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 3.7 (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 3.8 Relationship between porosity, depth of burial and overburden pressure. N = 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 3.9 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 (P/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 3.10 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 3.11 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 3.12 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 3.13 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 3.14 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 3.15 Total subsidence in Wilmington Oilfield area in 1954. (In: Chilingarian et al., 1995, p. 296, figure 6.8.)
Figure 3.16 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 3.17 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 3.18 Subsidence profiles across the Picacho Fault, AZ. (Modified after Holzer and Thatcher, 1979; in: Gurevich and Chilingarian, 1993, figure 6, p. 247.)
Figure 3.19 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 3.20 Distribution of oilfields in the Los Angeles Basin, CA. (After California Division of Oil and Gas, 1961.)
Figure 3.21 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 3.22 Horizontal movements and subsidence rates in the area of the Baldwin Hills Dam. (Modified after Lee, 1976, p. 301, figure 1.)
Figure 3.23 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 3.24 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 3.25 Playa Del Rey Oilfield with contours on top of the Franciscan Schist. (After California Division of Oil and Gas, 1963, p. 634.)
Figure 3.26 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 3.27 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 3.28 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 3.29 The cross-section and geologic structure of the Salt Lake Oilfield. (After California Division of Oil and Gas, 1961, p. 652.)
Figure 3.30 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 3.31 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 3.32 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 3.33 Wilmingtion Oilfield subsidence unit: 1973 to 1974 subsidence in feet. (After California Division of Oil and Gas, Sixth Annual Report.)
Figure 3.34 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 3.35 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 3.36 Curve showing cumulative total production versus cumulative total subsidence of the Wilmington Oilfield, CA (After Mayuga and Allen, 1998.)
Figure 3.37 Historical oil production, water injection and subsidence in the Wilmington Oilfield, CA. (After Mayuga and Allen, 1998.)
Figure 3.38 Diagrammatic shale-water flow to low-pressure permeable sands. (After Colazas and Strehle, 1995; in: Chilingarian et al., 1995.)
Figure 3.39 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 3.40 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 3.41 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 3.42 Relationship between Δh/h and formation pressure drop due to production (Δp = p_t – 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 3.43 Bolivar Coastal Fields (BCF). (After Finol and Sancevic, 1995; in: Chilingarian et al., 1955, p. 341.)
Figure 3.44 Stratigraphic section of Bolivar Coastal Fields. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 343, figure 7.30.)
Figure 3.45 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 3.46 Main leveling network and subsidence contours. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 350, figure 7.8.)
Figure 3.47 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 3.48 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 3.49 Subsidence history and prediction along the Bachaquero dike. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 349, figure. 7.6.)
Figure 3.50 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 3.51 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 3.52 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 3.53 Simplified view of the Po-Veneto Plain. The triangles indicate main hydrocarbon reservoirs. After Btrighenti et al., 1995; in: Chilingarian et al., 1995.)
Figure 3.54 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 3.55 Schematic cross-section of the Po Basin. (After Brighenti et al., 1995; in Chilingarian et al., 1995, p. 239, figure 5.19.)
Figure 3.56 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 3.57 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 3.58 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 3.59 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 3.60 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 3.61 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 3.62 Representative porosity log from an Ekofisk well. (After Boade et al., 1989; in: Chilingarian et al., 1995, p. 378, figure 8.3.)

Chapter 4

Figure 4.1 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 4.2 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 4.3 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 4.4 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 4.5 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 4.6 800,000-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 4.7 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 4.8 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 4.9 Relationship between the temperature and the solubility of CO₂ in water. (Data obtained from Wallace, 2009.)
Figure 4.10 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 4.11 Global volcanism over time 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 4.12 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 4.13 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 4.14 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 4.15 Solar irradiance (W/m²) and CO₂ concentrations in atmosphere (p-pmv) in Northern Hemisphere (solid dots). (Modified after Hoyt and Schatten, 1997.)

Chapter 5

Figure 5.1 Comparison of well sites.
Figure 5.2 Well casings.
Figure 5.3. Volumetric percentages of additives in fracturing fluids.
Figure 5.4 Proppant size and placement.
Figure 5.5 Proppant’s shape.
Figure 5.6 Proppant hardness.
Chart 5.1 Contaminants in produced water.

Chapter 6

Figure 6.1 Interrelationship among electrical potential (E), current (I) and resistance (R). (After Chilingar et al., 2008, Figure 1.1, p. 4.)
Figure 6.2 Schematic diagram of electrochemical reactions. (After Chilingar et al., 2008, figure 1.2, p. 60.)
Figure 6.3 Schematic diagram of electrochemical process. (After Chilingar et al., 2008, figure 1.3, p. 7.)
Figure 6.4 Corrosion cell showing flow of electrons and electrical current. Corrosion occurs at the anode. (After Chilingar et al., 2008, figure 1.4, p. 8.)
Figure 6.5 Effect of the ration of the area of cathode to the area of anode on corrosion rate. (After Chilingar et al., 2008, figure, 1.5, p. 15.)
Figure 6.6 Zn-Cu cell and polarization. (After Chilingar et al., 2008, Figure 1.6, p. 16.)
Figure 6.7 Polarization diagram of zinc corroding in acid. E_corr = mixed (corrosion) potential where oxidation and reduction are occurring equally, i.e., zinc dissolution is equal to hydrogen as evolution. (Modified after Jones, 1988, p. 163, figure 1A 3.)
Figure 6.8 Empirical relationship between corrosion rate and brine production for the interior areas of tubing. (Modified after Gatzke and Hausler, 1983; in: Chilingar et al, 2008, p. 29, figure 1.13.)
Figure 6.9 Relationship between corrosion rate and gas production inside tubing for gas production. (Modified after Gatzke and Hausler, 1983; in: Chilingar et al., 2008, p. 30, figure 1.14.)
Figure 6.10 Bent nail in seawater showing the flow of electrons (and electrical current)–stress cell. (After Chilingar et al., 2008, p. 41, figure 2.1.)
Figure 6.11 Relationship between endurance strength of steel (stress) and number of cycles needed for the occurrence of failure in corrosive and noncorrosive environments. (Modified after Bertness, 1957, p. 131, figure1. In: Chilingar et al., p. 45, figure 2.4.)
Figure 6.12 Schematic diagrams of bacterial morphology. (http://enwikiedia.org.)
Figure 6.13 Schematic diagram of sulfide corrosion under aerobic slime deposit. Corrosion of iron by H₂S, generated by sulfate reducers. (After Chilingar et al., 2008, p. 64, figure 3.4.)
Figure 6.14 Casing potential profile test equipment and example of plotting data. Modified after Jones, 1988, p. 66, figures 1 & 2; in: Chilingar et al., 2008, p. 102, figure 5.3.)
Figure 6.15 Installation of galvanic anodes. (Modified after NACE, Houston, TX, Control of Pipeline Corrosion, 1979, figure 8.6; in: Chilingar et al., 2008, p. 103, figure 5.4.)
Figure 6.16 Leak frequency, Clairmont Field, Kent County, TX. (After Kirklen, 1973, figure 4; in: Chilingar et al., 2008, figure 5.5, p. 107.)
Figure 6.17 Schematic diagram of cathodic protection for a pipeline. (In: Chilingar et al., 2008, p. 73, figure 4.2.)
Figure 6.18 Diagram illustrating the theory of cathodic protection. I” = current required to produce complete cathodic protection. Current must exceed equilibrium corrosion current I’ to provide any protection. Corrosion will cease when the flow of cathodic current (I“) increases cathodic polarization to the open circuit potential (E_A) of the anode as shown at point A. (After Chilingar et al., 2008, p. 72, figure 4.1.)
Figure 6.19 Adjustable interference bond across an insulating (isolating) flange connecting a buried flowline to cathodically protected casing. (After Jones, 1988, p. 34, figure 14.6; in: Chilingar et al., 2008, p. 110, figure 5.7.)
Figure 6.20 Measurement of pipe-to-soil potential on a pipeline. (After Jones, 1988, p. 32, figure 14.4; in: Chilingar et al., 2008, p. 110, figure 5.8.)
Figure 6.21 Wenner method (four terminal method) of measuring soil resistivity. Distance “b” (depth of electrode) is smaller than distance “a” (electrode spacing). The resistivity, ρ = 2πα(E/I), is averaged to a depth approximately equal to “a“. (After Parker and Peattie, p. 4, figure 1.4; in: Chilingar et al., 2008, p. 112, figure 5.9.)
Figure 6.22 Soil profile along a pipeline. Resistivity values are plotted on the ordinate (log scale), whereas distances along pipeline are plotted on the abscissa. A = anodic hot spot. (After Parker and Peattie, 1999, p. 9. figure 1.8; in: Chilingar et al., 2008, p. 113, figure 5.10.)
Figure 6.23 Flow of electrons and electric current between the interconected new and old pipelines. After Chilingar et al., 2008, p. 114, figure 5.11.)
Figure 6.24 Schematic showing various areas of concern pertaining to potential corrosion of an offshore facility. (After Brondel et al., 1994.)
Figure 6.25 Schematic of offshore jackup rig illustrating corrosive environment of the various portions of the rig. (After Brondel et al., 1994.)

Chapter 7

Figure 7.1 Solubilty of frequently found inorganic scales vs. temperature found in oilfield operations. (Modified after Crabtree et al., 1999, p. 31.)
Figure 7.2 The solubility of barium sulfate BaSO₄ vs. ressure. Modified after Crabtree et al., 1999, p. 31)
Figure 7.3 Solubility of strontium sulfate vs. salinity at various temperatures. (Modified after Crabtree et al., 1999, p. 31.)
Figure 7.4 Relationship between solubility of CaCO₃ and temperature. (After Carlberg et al., 1962; in Chilingar et al., 2008, p. 122, figure 6.2.)
Figure 7.5 Relationship between temperature and solubility of gypsum and anhydrite in fresh water. (After Carlberg et al., 1962; in: Chilingar et al., 2008, p.120, figure 6.1.)
Figure 7.6 Relationship between solubility of NaCl concentration (g/L) and solubility of gypsum scale at 95 °F. (After Fulford, 1968; in: Chilingnar et al., 2008, p. 124, figure 6.3 courtesy of SPE)
Figure 7.7 Relationship between the total dissolved solids (TDS) and approximate solubilities of strontium sulfate and barium sulfate in oilfield brines at 60 °C. (Modified after Jones, 1988, p. 124, Chilingar et al., 2008, p. 132, figure 6.8.)
Figure 7.8 Determination of K for various ionic strengths. (Modified after Stiff and Davis, 1952; in: Chillingar et al., 2008, p. 128, figure 6.4.)
Figure 7.9 Determination of values for pCa and pAlk from concentrations of [HCO₃⁻, CO₃⁼, (After Langelier, 1936; in: Chillingar et al., 2008, p. 129, figure 6.5.)
Figure 7.10 Variation of S_f with temperature and pressure. (Modified after Jones, 1988, p. 121; in: Chilingar et al., p. 130, figure 6.6.)
Figure 7.11 Relationship between pH and R′ value. (Modified after Jones, 1988; in: Chilingar et al., 2008, p. 130, figure 6.7.)
Figure 7.12 Solubility of CaCO₃-MgCO₃-H₂O system at P_CO2 ≈ 1 atm and temperatures ranging from 0° to 70 °C. Points between ordinate and 45°-line represent solubility of calcite-dolomite mixtures, whereas those between the 45°-line and abscissa represent dolomite-magnesite mixtures. (After Yanat’eva, 1954, p.777; in: Chilingar et al., 2008, p. 133, figure 6.9.)
Figure 7.13 Graph showing the growth of the number and total capacity of the sulphate reduction plants (SRP) built in recognition of the formation plugging that can occur when a foreign water is injected into a reservoir. (Modified after Mackey, 2008, slide 17.)

List of Tables

Chapter 2

Table 2.1 Typical composition of natural gases expressed in mole % (or volume %). (In: Chilingar et al., 1969, table 1, p.89.)
Table 2.2 Physical constants of light hydrocarbons and other components associated with natural gas. (Data abstracted from Natural Gas Processors Suppliers Association, 1981.)
Table 2.3 Types of chemical reaction leading to methane formation. (Modified after Kaplan, 1004, figure 1, p. 298.)
Table 2.4 Ranges of carbon and deuterium isotope ratios for methane derived from different origins. (After Kaplan, 1994, table 2, p. 301.)
Table 2.5 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 3

Table 3.1 Subsidence found in various cities as a result of fluid withdrawal. (Modified after Nelson, 2015.)
Table 3.2 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 3.3 Depth and thickness of Wilmington Oilfield oil zones. (After Colazas, 1971; in: Chilingarian et al., 1995, table 6–11, p. 291.)
Table 3.4 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 3.5 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 3.6 Ekofisk reservoir data. (After Snyder, 1971; in Chilingarian et al., 1995, table 8.1 p. 375.)

Chapter 5

Table 5.1 Well comparisons, lists various sites also known as plays throughout North America.
Table 5.2 Chemicals used in fracking.
Table 5.3 Volume of water required for development of various resources.
Table 5.4 NAAQS criteria pollutants.

Chapter 6

Table 6.1 The electromotive force series or the electrode potential of an element according to decreasing tendency to release electrons.
Table 6.2 Variation in actual electrode potential of iron and cadmium with a change in concentration of ions.
Table 6.3 Microorganisms found in oilfield waters. (Modified after Jones, 1988, p. 130.)
Table 6.4 Bacterial control agents. (After Jones, 1988, p. 134; in: Chilingar et al., 2008. table 3.2, p. 65.)
Table 6.5 Common inhibitors. (After Jones, 1988, p. 20; in: Chilingar et al., 2008, table 4.1, p. 84.)
Table 6.6 Corrosion rate of steel in soil. (After Romanoff, 1957; in: Chilingar et al., 2008, table 5.2, p. 112.)
Table 6.7 Advantages and disadvantages of galvanic protection. (After Cron and Marsh, 1983; in: Chilingar et al., 2008, table 8.5, p. 219.)
Table 6.8 Advantages and disadvantages of impressed-current cathodic protection. (After Chilingar et al., 2008, table 8.6, p. 220.)

Chapter 7

Table 7.1 Common oilfield scales.
Table 7.3 Cause of scale formation. (After Wright and Chilingarian, 1989, p. 326; in: Chilingar et al., 2008, table 6.1, p. 119.)
Table 7.2 Oil field scales. Data drawn from handbook of chemistry and physics (1980), Petrowiki (2016) and Mackay (2007).
Table 7.4 Examples of water analysis. (Modified after Jones, 1988, p. 112; in: Chilingar et al., 2088, table 6.4, p. 124.)
Table 7.5 Factors for converting ion concentration (mg/L or meq/L) to ionic strength. Concentrations must be multiplied by the factors shown. (After Jones, 1988; in: Chilingar et al., 2008, table 6.3, p. 120.)
Table 7.6 Comparison of various mechanical, chemical, and jet-blasting scale-removal techniques. (Modified after Crabtree et al., 1999).

Scrivener Publishing
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Environmental Aspects of Oil and Gas Production

John O. Robertson

George V. Chilingar

Contributors:

Moayed bin Yousef Al-Bassam, PhD – Corrosion

Michael D. Holloway, PhD – Fracturing

This edition first published 2017 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
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ISBN 978-1-119-11737-7