Understanding Petroleum Reservoirs: Towards an Integrated Reservoir Engineering and Geochemical Approach (Geological Society Special Publication No. 237)

Contents......Page 6
Understanding petroleum reservoirs: towards an integrated reservoir engineering and geochemical approach. Introduction......Page 8
Interpretation of charging phenomena based on reservoir fluid (PVT) data......Page 14
Fig. 1. Molar concentration profile of low maturity oil, Oak field, British .........Page 15
Fig. 2. Relationship of SF(P[sub(10+)]) and API gravity in oils of increasing .........Page 17
Fig. 4. Relationship of light end and liquid component Slope Factors in .........Page 18
Table 3. Comparison of PVT characteristics of oil in the Brazeau River .........Page 20
Fig. 6. Molar concentration profile of the Cardium Formation oil, Brazeau River .........Page 21
Fig. 9. Decreasing values of SF(C[sub(3)]–nC[sub(5)]) accompanied by increasing levels of H[sub(2)]S .........Page 22
Fig. 10. Values of SF(C[sub(3)]–nC[sub(5)]) and SF(P[sub(10+)]) in the oils and gas-condensates .........Page 23
Fig. 11. Slope Factors based on compositions generated using the PVT program .........Page 24
Fig. 12. Values of SF(C[sub(3)]–nC[sub(5)]) and SF(P[sub(10+)]) in oils and closely related .........Page 26
Fig. 13. Correlation of saturation pressure (dew point) of gas-condensates with SF(P[sub(10+)]) .........Page 28
Fig. 14. SF(C[sub(3)]–nC[sub(5)]) versus saturation pressures for the oils and gas-condensates of .........Page 29
Fig. 16. Calculated (WinProp) compositions of gas-condensates derived from the oils of .........Page 30
Table 1. Slope Factors representing asphaltene pyrolysates, and oils of Rainbow and .........Page 16
Table 2. Initial volumes of petroleum in place in Alberta by stratigraphic interval (excluding tar sands)......Page 19
Table 5. Slope Factor and phase separation data for Experiments 1, 2 and 3......Page 25
Table 6. Characteristics of closely associated oil and gas-condensate pairs......Page 27
Shaken but not always stirred. Impact of petroleum charge mixing on reservoir geochemistry......Page 34
Fig. 1. Variation in concentrations for major and minor components of geochemical .........Page 36
Fig. 3. Variation in concentration of hopanes in the sample set with .........Page 37
Fig. 5. Sterane and hopane concentrations (as defined in Fig. 1) in end .........Page 38
Fig. 6. Acyclic alkane, hopane and tetracyclic alkane cross plots of end .........Page 39
Fig. 7. Cross plots of calculated vitrinite reflectance equivalent biomarker maturity (Ro Ts) .........Page 40
Fig. 8. The distribution of fraction-specific 'maturity' for the oils and condensates .........Page 41
An overview of developments related to the characterization and significance of high molecular weight paraffins/hydrocarbons (>C[sub (40)]) in crude oils......Page 44
Fig. 2. Extensively biodegraded oils may not appear to contain any n-hydrocarbons, .........Page 47
Fig. 3. (a) Oils derived from marine source rocks are characterized by a .........Page 48
Fig. 4. A number of oils from the Rimbey–Meadowbrook reef trend in .........Page 49
Fig. 5. Source rock extracts have now been shown to possess HMWHCs .........Page 50
Fig. 6. The complexity of the branched/cyclic HMWHC fraction is illustrated in .........Page 52
Fig. 7. Six homologous series of monomethylalkanes have been tentatively identified in .........Page 53
Fig. 8. n-Alkylcyclopentanes, n-alkylcyclohexanes and methyl-n-alkylcyclohexanes can be readily detected in the .........Page 54
Fig. 9. n-Alkylbenzenes, n-alkyltoluenes and n-alkylxylenes can be readily detected in the .........Page 55
Table 1. Melting points of some individual compounds to illustrate variations resulting .........Page 51
Effects and impact of early-stage anaerobic biodegradation on Kuparuk River Field, Alaska......Page 60
Fig. 1. General location map of Kuparuk River Unit shows drill site .........Page 61
Fig. 2. Kuparuk River stratigraphy: (a) unit type log and stratigraphic diagram .........Page 62
Fig. 3. Kuparuk River Field fault distribution: Note, large older NW–SW trending .........Page 63
Fig. 4. Box plot distribution of Kuparuk A and Kuparuk C crude .........Page 64
Fig. 5. Locations of oil samples with <20° API superimposed on map .........Page 65
Fig. 6. Shaded polygons for (a) Kuparuk River A Formation or (b) .........Page 67
Fig. 7. Gas line plot (after Chung et al. 1988) for Kuparuk .........Page 75
Fig. 8. Plot of light hydrocarbon (LHC) whole oil GC ratios for .........Page 77
Fig. 9. Whole oil gas chromatograms of oils from diverse parts of .........Page 78
Fig. 10. GCMS total ion current (TIC) for aromatic hydrocarbon fractions are .........Page 79
Fig. 11. Long chain alkyl aromatic normal patterns have a full homologous .........Page 80
Fig. 12. Long chain alkyl aromatics for the most downdip well, 1J-14. .........Page 81
Fig. 12. Long chain alkyl toluenes (m/z = 106) also show variable depletions. (e) .........Page 82
Fig. 13. GCMS total ion current (TIC) for aromatic hydrocarbon fractions from .........Page 83
Fig. 14. Plot of LCAA ratios with depth (true vertical sub-sea) for .........Page 84
Fig. 15. Rock-Eval 6 pyrograms of cores from 2X-02 well: (a) Kaparuk .........Page 85
Fig. 16. Rock-Eval 6 calibrations: (a) calibration curve relating Rock-Eval 6 Y .........Page 86
Fig. 17. Plot of Rock-Eval 6 with depth (true vertical subsea) for .........Page 87
Fig. 18. EDS spectra of (a) un-oxidized green glauconite 1L-07, (b) oxidized brown .........Page 88
Fig. 19. Low magnification back-scatter electron (BSE) image of Kuparuk C sandstone .........Page 89
Fig. 20. BSE images showing different morphologies of FeO/OH in enriched glauconite .........Page 90
Fig. 21. High magnification BSE image of bright amorphous FeO/OH enriched glauconite .........Page 91
Table 1. Gas isotope data......Page 68
Table 2. Whole oil GC ratios......Page 69
Table 3. Selected carbon isotopic data for hydrocarbon fractions......Page 71
Table 4. Aromatic hydrocarbon GC/MS ratios......Page 72
Table 5. Rock-Eval 6 data.......Page 73
HCToolkit/EOS interface: an open source, multi-platform phase equilibria framework for exploring phase behaviour of complex mixtures......Page 96
Fig. 2. Phase::Flash class layout.......Page 98
Fig. 3. Layout of the parts of the EOSInterface.......Page 100
Fig. 4. Example HCToolkit code.......Page 101
Fig. 6. Predictions of methane solubility in water. Shown is the bubble .........Page 102
Fig. 7. Dead oil compositions, Vermillion area. The left figure shows a .........Page 103
Fig. 9. Calculated phase envelopes for condensate with increasing amounts of added .........Page 104
Rates of reservoir fluid mixing: implications for interpretation of fluid data......Page 106
Fig. 1. Simple reservoir description used in analysis of fluid mixing. The .........Page 109
Table 1. Base model assumptions......Page 110
Fig. 4. Relative fluid mixing times for the scenarios described in the .........Page 111
Fig. 5. Simple reservoir geometry used for modelling fluid pressure equilibration. Note .........Page 113
Fig. 6. Comparison of mixing times generated by the analytical relation in .........Page 114
Fig. 8. Absolute fluid mixing times for the scenarios described in the .........Page 115
Fig. 10. Nomogram for calculating mixing times from knowledge of volume change .........Page 117
Fig. 11. Map of the Ross oil field. Inset shows location. The .........Page 118
New insights into reservoir filling and mixing processes......Page 122
Fig. 2. Trends of fluid pressures versus depth in a West African .........Page 123
Fig. 3. Solution GOR and API gravity of oils from a West .........Page 124
Fig. 5. Trends of API gravity of oils with depth below top .........Page 125
Fig. 7. Trends of bubble point (P[sub(b)]) of oils with depth below .........Page 126
Fig. 9. GOR versus API gravity of oils in single reservoirs from .........Page 127
Fig. 10. Models of trap filling. Perfect mixing. In this widely accepted .........Page 128
Fig. 11. The inadequacy of diffusive mixing, even after geological time periods. .........Page 129
Fig. 12. Models of trap filling. Very poor mixing. In this model, .........Page 130
Fig. 13. Model predictions of API gravities of oils in a West .........Page 131
Fig. 14. Model predictions of GOR of oils in a West African .........Page 132
Fig. 16. Model predictions of API gravities of oils in a single .........Page 133
Fig. 18. Volume versus depth curve of a spherical-circular trap with a .........Page 134
An integrated basin modelling study applying asphaltene kinetics from reservoired petroleum in the Snorre Area, northern North Sea......Page 140
Fig. 1. Regional framework in this study. BCU map of the Tampen .........Page 141
Fig. 2. Conceptual models of the three simulated 2D lines. Location are shown on Figure 1.......Page 145
Fig. 3. Kinetic signature of the Draupne Source Rock in the study .........Page 147
Fig. 4. Source rock quality described by TOC and HI in the .........Page 148
Fig. 5. (b) Simulated temperature against well data (present situation).......Page 149
Fig. 6. Maturity evolution from asphaltene kinetics in Kitchen 1 defined in .........Page 152
Fig. 7. Maturity development in the deepest are in the 34/5 kitchen .........Page 153
Fig. 8. Maturity in the 34/4-3 well from asphaltene kinetics, indicating that .........Page 154
Fig. 9. Migration from the north of Snorre shown for 58 Ma .........Page 155
Fig. 10. Migration from the east of Snorre for 58 Ma and .........Page 157
Fig. 11. Assumed filling direction from the east into the Snorre structure .........Page 159
Fig. 12. Effective stress evolution in a pseudo-well on the top of .........Page 160
Table 1A. The wells used in this study with an overview of available calibration data......Page 142
Table 1B. Conceptual framework and principal petroleum system element defined in the basin model......Page 143
Table 2. Proposed kinetic models for the Draupne formation, based on kerogen and asphaltenes......Page 146
Development of a compositional kinetic model for hydrocarbon generation and phase equilibria modelling: a case study from Snorre Field, Norwegian North Sea......Page 164
Fig. 1. General distribution of GOR as a function of reservoir temperature, .........Page 165
Table 1. Comparison of saturation pressure and volumetries of phase separation at .........Page 167
Fig. 3. Compositional kinetics of Dieckmann et al. (1998).......Page 170
Fig. 4. Saturation pressure (P[sub(sat)]) versus formation volume factor (Bo) of the .........Page 171
Fig. 5. Geological model used for tuning of the compositional kinetics. Black .........Page 172
Table 4. Tuned compositional kinetic model......Page 173
Fig. 7. Location map of the Tampen Spur reservoirs and cross section .........Page 174
Fig. 8. Simulated extent of kerogen transformation in the kitchen area of .........Page 176
Table 5. Comparison of reservoir fluid properties simulated for the Snorre reservoir .........Page 177
Fig. 11. Evolution of reservoir phase saturation pressure of the instantaneous and .........Page 178
Table 2. Structure of compositional kinetic schemes available to date......Page 168
Table 3. Example of a C[sub(7+)] compositional description commonly used in PVT analysis......Page 169
A petroleum charge model for the Judy and Joanne Fields, Central North Sea: application to exploration and field development......Page 182
Fig. 1. Location map.......Page 183
Fig. 2. Regional tectonic elements map.......Page 184
Fig. 3. Top Triassic reservoir map.......Page 185
Fig. 4. Generalized stratigraphy of the J Block area.......Page 186
Fig. 5. Petroleum occurrence map.......Page 187
Fig. 7. Biomarker maturity crossplot for J Block petroleums.......Page 188
Fig. 8. Wax content versus maturity for J Block petroleums.......Page 189
Fig. 9. GC traces for Pre-Cretaceous petroleums from 30/7a-P5z and 30/7a-P7.......Page 191
Fig. 10. Triterpane fingerprints for Pre-Cretaceous petroleums.......Page 192
Fig. 11. Galimov plot for 30/7a and 30/13 petroleums.......Page 193
Fig. 12. RFT pressure versus depth for Pre-Cretaceous reservoirs—gross scale.......Page 194
Fig. 13. RFT pressure versus depth for Pre-Cretaceous reservoirs – detail.......Page 195
Fig. 14. Pre-Cretaceous charge model summary map.......Page 196
Fig. 15. Location map showing Chalk oils analysed.......Page 197
Fig. 16. RFT pressure versus depth for Chalk reservoirs.......Page 200
Fig. 17. Strontium isotope ratio versus depth for Chalk core extracts.......Page 201
Fig. 18. Location map showing Palaeocene petroleums analysed.......Page 204
Fig. 19. Schematic cross-section showing summarized charge model.......Page 206
Fig. 20. Typical whole oil GC and detailed region used for GC fingerprinting.......Page 209
Fig. 21. Dendrogram from hierarchical cluster analysis of Judy Field petroleums.......Page 210
Fig. 22. Map showing oil families denned by cluster analysis.......Page 211
Fig. 23. Dendrogram showing alternative clustering of oil families.......Page 212
Table 1. Pre-Cretaceous test data and fluid properties......Page 190
Table 2. Chalk test data and fluid properties......Page 199
Table 3. Palaeocene test data and fluid properties......Page 205
Compositional grading in the oil column: advances from a mass balance and quantitative molecular analysis......Page 214
Fig. 1. Proposed workflow process for a reservoir compartment study.......Page 215
Fig. 2. General base map of the Val D'Agri region. The well .........Page 216
Fig. 4. Spider-plot display of geochemical data corresponding to typical light and .........Page 218
Fig. 6. Depth profiles of the API gravity according to compartment in .........Page 219
Fig. 8. Cross plot of the API gravity and total sulphur content .........Page 220
Table 3. Averaged molecular ratio data with thermal maturity significance for light and heavy oils......Page 221
Fig. 10. Illustration of the mass balance relationships that occur to individual .........Page 222
Fig. 11. Cross plot of individual quantitative results from three molecular weight .........Page 223
Fig. 13. Averaged data display for the gasoline range hydrocarbons (C[sub(5)–C[sub(7)]) for .........Page 224
Table 4. Results of the mass balance calculations based on quantitative GC analysis......Page 225
Fig. 15. Benzothiophene (BT) and dibenzothiophene (DBT) data from individual samples in .........Page 226
Table 1. Summary of basic knowledge and data for the Val D'Agri sample set......Page 217
Application of geochemistry in the evaluation and development of deep Rotliegend dry gas reservoirs, NW Germany......Page 228
Fig. 1. Voelkersen field location (arrow on insert map of Germany, upper .........Page 229
Table 1. Voelkersen field Rotliegend gas composition (volume %)......Page 230
Fig. 3. Comparison of carbon and hydrogen stable isotopic composition of gas .........Page 232
Table 3. Carbon and hydrogen isotopic composition of Voelkersen Rotliegend gas samples......Page 233
Fig. 5. Methane to pentane carbon stable isotope composition of gases produced .........Page 234
Fig. 6. Cross plots of ethane δ[sup(2)]H isotope composition versus ethane carbon .........Page 235
Fig. 7. Voelkersen Rotliegend field compartment model based on geochemical data (structure map top Dethlingen sandstone).......Page 236
Table 2. Gas sampling parameters......Page 231
Fluid properties, phase and compartmentalization: Magnolia Field case study, Deepwater Gulf of Mexico, USA......Page 238
Fig. 2. Shaded relief bathymetry in the vicinity of the Titan mini-basin .........Page 240
Fig. 3. Magnolia Field well locations and generalized fault pattern in relation .........Page 241
Fig. 4. North–south seismic line shown in Figure 3 illustrating the stratigraphic .........Page 242
Fig. 6. Saturation pressure against oil and condensate API gravity for Magnolia .........Page 244
Fig. 7. Whole oil gas chromatograms of (A) a saturated low gravity .........Page 245
Fig. 8. Hopane biomarker ratios C[sub(29)]/C[sub(30)] against C[sub(35)]/C[sub(34)] (Table 2) of Magnolia oils .........Page 246
Fig. 10. Saturate (Ts/Ts+Tm) and aromatic (MPI-1) biomarker maturity indicators for Magnolia .........Page 248
Fig. 12. Condensate and oil maturity-sensitive ratio of 2,4-dimethylpentane to 2,3-dimethylpentane versus .........Page 250
Fig. 14. Benzene/methylcyclohexane (Bz/MCH) against dibenzothiophene/1 + 4-methyldibenzothiophene DBT/4 + 1-MDBT) of oil and condensate .........Page 251
Fig. 15. nC[sub(7)]/methylcyclohexane (nC[sub(7)]/MCH) versus toluene/nC[sub(7)] (tol/nC[sub(7)]) of Magnolia oils and condensates .........Page 252
Fig. 16. Dryness (C[sub(1)]/ΣC[sub(1)] ... C[sub(5)]) versus methane carbon isotopic composition (δ[sup(13)]C[sub(c1)], ‰ PDB) for .........Page 253
Fig. 17. Ethane δ[sup(13)]C versus ethane content of associated gases from Magnolia .........Page 254
Fig. 18. Depth plot for a Magnolia Field appraisal well showing gas .........Page 255
Fig. 20. Log plot across one of the Magnolia pay zones showing .........Page 256
Fig. 22. Log plot from a sidetrack borehole drilled (for coring) approximately .........Page 257
Figure 23. δ[sup(13)]C[sub(c1)] versus δ[sup(13)]C[sub(c2)] for Magnolia MDT sample associated gases. Fields .........Page 258
Table 1. Summary of Magnolia Field fluid properties, corrected for drilling fluid contamination......Page 243
Table 2. Selected Magnolia fluid geochemical attributes discussed in text......Page 247
Table 3. Magnolia Field free and associated gas properties......Page 249
High temperature quartz cementation and the timing of hydrocarbon accumulation in the Jurassic Norphlet sandstone, offshore Gulf of Mexico, USA......Page 264
Fig. 2. Generalized stratigraphic section for the Jurassic in southwestern Alabama and Mobile Bay.......Page 265
Fig. 4. Generalized cross section through Fairway Field along A–A' in Figure 3. .........Page 266
Fig. 5. Wireline logs showing a typical well penetration in Fairway Field. .........Page 267
Fig. 6. Thin section photomicrographs of Norphlet Formation sandstones from Mobile Bay. .........Page 268
Fig. 7. Log porosity versus depth for the Norphlet in two wells .........Page 269
Fig. 8. Porosity versus air permeability for Norphlet sandstones from Mobile Bay. .........Page 270
Fig. 10. Thin section photomicrographs of grain-coating chlorite in Norphlet sandstones. (a) .........Page 272
Fig. 12. (a) Nodular patches of quartz cement, 1–3 mm in diameter, occur .........Page 273
Fig. 13. (a) Intergranular pressure solution (IPS) is frequently observed in the .........Page 274
Fig. 14. Intergranular volume (IGV) versus total cement for Norphlet sandstones from .........Page 275
Table 2. Summary of petrographic point-count data for Norphlet samples, Mobile Bay......Page 276
Fig. 16. Burial history model for the Norphlet Formation at Fairway Field .........Page 277
Fig. 17. Small discontinuities in chlorite grain coats are common in the .........Page 279
Fig. 18. (a) Quartz cement volume versus the percentage of quartz grain .........Page 280
Fig. 19. Results of compaction and quartz cementation models calculated using quantitative .........Page 281
Table 1. Chemical composition (mg/l) of Norphlet Formation waters, Fairway Field, offshore Alabama......Page 271
Table 3. Sulphur isotope data......Page 278
Evidence of reservoir compartmentalization by calcite cement layers in deepwater sandstones, Bell Canyon Formation, Delaware Basin, Texas......Page 286
Fig. 2. Gamma-ray, neutron and density logs from the East Ford Unit .........Page 287
Fig. 3. Cross section A–A' of south end of East Ford field. Four .........Page 288
Spatial variations in the composition of formation waters from the central North Sea: implications for fluid flow in the deep high-pressure high-temperature hydrocarbon play......Page 290
Fig. 1. Location and structural elements of the Central Graben, North Sea. .........Page 291
Fig. 2. Regional stratigraphic column for the Central North Sea highlighting potential .........Page 292
Fig. 4. Comparison of water (solid symbols) and ERSA (open symbols) sample .........Page 297
Fig. 5. Star plots showing the average relative compositions (from Table 4) of .........Page 300
Fig. 7. Geographical distribution of the water types (numbered). Symbol shapes identify .........Page 301
Fig. 8. Overpressure distribution map for the study area.......Page 302
Fig. 9. Schematic detailing the characteristics of fluid barriers or pressure cell boundaries within the study area.......Page 303
Fig. 10. Examples of relationships between pressure cell boundaries, changes in water .........Page 305
Fig. 11. Mean PC 1 and PC 2 factor scores for ERSA/CERSA data .........Page 307
Table 1. Source of data used in the study......Page 294
Table 2. Summary of data reproducibility and consistency of reproducibility......Page 296
Table 3. Grouping of wells based on PCA/CA results for water sample data......Page 298
Table 4. Average compositions of water types......Page 299
Table 5. Relationships between locations of pressure cell boundary, changes in water .........Page 304
Table 6. Water types derived from visual grouping of ERSA/CERSA PCA PC 1 and PC 2 factor scores......Page 308
Petroleum migration, faults and overpressure. Part II. Case history: The Haltenbanken Petroleum Province, offshore Norway......Page 312
Fig. 1. (a) The overpressure in the Haltenbanken Area is generally confined .........Page 313
Fig. 1. (b) The large scale westward dipping and faulted configuration of the .........Page 315
Fig. 2. Illustration of the general trend of the faults. Please note .........Page 316
Fig. 3. Organic rich rocks in Haltenbanken include the coals and shales .........Page 317
Fig. 4. Whilst the Smørbukk and Smørbukk Sør fields (Fig. la) today .........Page 318
Fig. 5. Structural details and pressure domains of the Smørbukk region, reproduced .........Page 319
Fig. 6. Lack of pressure-leakage results in overpressure development in the terminal .........Page 320
Fig. 7. Is a bad caprock in fact a good caprock if .........Page 321
Fig. 8. Movement on a fault plane may result in juxtaposition of .........Page 322
Fig. 9. The temperature for fluid inclusion formation in quartz is translated .........Page 323
Fig. 10. Early expulsion from a deeper source rock, e.g. the Åre .........Page 324
Fig. 11. The δ[sup(13)]C values of the C[sub(10+)] fraction from fields in .........Page 329
Fig. 12. Current Spekk Formation maturities in the Smørbukk region illustrate that .........Page 331
Fig. 13. The dry structures 6506/12-4 and 6506/11-1 west of Smørbukk contain .........Page 333
Fig. 14. The highly segmented nature of the 'multi-stacked play zones' in .........Page 334
Fig. 15. The diesel GC-FID signature of the core extracts from well .........Page 335
Fig. 16. 6506/12-1 DST 7 (Garn Formation) exemplifies molecular distributions in the Garn .........Page 337
Fig. 17. UV-photomicrographs of thin sections and cleansed sandstones. All depths are .........Page 339
Fig. 18. The amount of methane in bulk crushed cleansed sand grains .........Page 341
Fig. 19. The amount of fluorescent petroleum inclusions in several Smørbukk wells .........Page 342
Fig. 21. Tilted rotated fault blocks with repetitive clastic lithologies of sandstones, .........Page 343
Fig. 22. The gas liberated from inclusions in cleansed sand grains from .........Page 345
Fig. 23. Principal component plot of the composition of the gas liberated .........Page 346
Table 3. Biomarker parameters......Page 347
Fig. 25. Biomarkers extracted from inclusion in different wells in Smørbukk show .........Page 348
Fig. 26. The sterane distribution for fluid inclusions from Halten Vest is .........Page 349
Fig. 28. The maturity variation in Smørbukk DST fluid samples is much .........Page 350
Fig. 29. Haltenbanken fluids are phase separated reflecting the vertical migration, and .........Page 352
Fig. 30. GOR in petroleums off Mid-Norway. The 'phase envelope' represents an .........Page 353
Fig. 31. (a) Filling a fault block through a fault. A petroleum column .........Page 354
Fig. 31. (b) Diagenesis may partly heal the fault zone during progressive .........Page 355
Fig. 32. Filling of simple dome-shaped structures (a) results in more homogeneous .........Page 356
Table 2. Variation inpristane to phytane (Pr/Ph), pristane to n-C[sub(17)] and n-C[sub(18)] .........Page 338
A mass balance approach for assessing basin-centred gas prospects: integrating reservoir engineering, geochemistry and petrophysics......Page 380
Fig. 1. Schematic diagram illustrating elements of the mass balance process model .........Page 384
Fig. 2. Stratigraphic column for the Bossier Sands, East Texas Basin (Montgomery 2000).......Page 386
Fig. 4. Vertical distribution of present-day Bossier shale TOC values taken from .........Page 387
Fig. 5. Present-day kerogen type and quality of Bossier shales in the .........Page 388
Fig. 8. Variation of vitrinite reflectance with depth in the East Texas Basin.......Page 389
Fig. 10. Type log for the Bossier sands in the Dew/Mimms Creek Fields, Freestone Country, Texas.......Page 390
Fig. 12. Incremental mercury intrusion plot used to identify hydraulic rock types .........Page 392
Fig. 13. Range of effective porosity and absolute permeability for Bossier sand .........Page 393
Fig. 15. Histograms of the P[sub(10)], P[sub(50)] and P[sub(90)] gas volumes computed with .........Page 394
D......Page 398
H......Page 399
N......Page 400
R......Page 401
W......Page 402