ALBERT

Description: A 300-m (1000-ft)-thick succession of shallow- and warm-water carbonates has been studied in well cores from the southernmost Barents Sea, offshore north Norway. These upper Paleozoic strata contain numerous zones of moderate to high porosity, including a wide range of depositional facies, despite moderately high burial temperatures and the absence of petroleum charge. Most porosity appears to be either primary or created during early (eogenetic) diagenesis. Negative correlation between porosity and both bulk-rock alumina content and stylolite frequency reflects the influence of phyllosilicate minerals in localizing stylolitic dissolution. This provides part of the explanation for the overall correlation between porosity and the platform's stratigraphic evolution. The early stage of mixed siliciclastic-carbonate deposition has low porosity because of extensive chemical compaction in aluminous beds. The following siliciclastic-poor stage shows upward-increasing porosity associated with aggradation of muddy buildups and wackestones, followed by the progradation of a more proximal facies belt of thinly bedded dolomitic mudstones. Maximum porosity development occurs in the overlying, little-dolomitized grain-shoal facies belt, which shows upward decrease in porosity because of a transgressive trend that developed progressively lower energy depositional conditions, favoring the occurrence of stylolite-prone shaly laminations. A general porosity-favorable factor is the presence of a stratified column of high-salinity brine, enforcing a closed diagenetic system during burial. Limestones and dolostones comprising this platform have very different proportions of low and high porosity values. Limestones have positively skewed frequency distribution (many samples 〈5% porosity), whereas dolostones have higher average porosity with symmetric distribution (few samples 〈5% porosity). The low limestone porosities result from cementation by coarse calcite-spar in grain-dominated samples and matrix compaction and cementation in muddy facies, features that are less common in dolostones possibly because of lesser propensity for stylolite development and the resistance of early-dolomitized matrix to compaction. Steve received a Ph.D. from the University of California at Los Angeles in 1978. He works on sandstone and carbonate petrology, sedimentology, and stratigraphy.

Description: The northern part of Honshu Island contains the major petroleum resources of Japan. The source rocks mainly comprise a sequence of Miocene marine mudstones that are overlain in places by thick Pliocene and Pleistocene sediments. In the past, mainly vitrinite reflectance analyses have been used to evaluate thermal maturities of these rocks. However, vitrinite reflectance suppression caused by compositional variation of vitrinite is common in marine-deposited rocks, and therefore, modeled estimations of the extent of petroleum generation from the Japanese sequences could be in error. Fluorescence alteration of multiple macerals (FAMM) analysis is a method that aids in solving the problem of vitrinite reflectance suppression and gives improved evaluations of thermal maturity. Combined vitrinite reflectance and FAMM analyses of potential source rock sequences intersected by the Ministry of International Trade and Industry (MITI) Shin-Takenomachi and MITI Nishi-Kubiki wells of the Niigata Basin and the MITI Honjo-Oki and MITI Yuri-Oki-Chubu wells of the Akita Basin show that vitrinite reflectance suppression is common in the Neogene source rocks. This leads to major differences between the depth profiles for vitrinite reflectance and for FAMM-derived, equivalent vitrinite reflectance. On the basis of vitrinite reflectance, the thermal maturity and hence, the petroleum source rock potential is underestimated for the Miocene Noudani Formation of the Niigata Basin and the Pliocene Funakawa and Miocene Onnakawa and Nishikurosawa formations of the Akita Basin. The new thermal maturity data indicate that these formations would have generated more oil than previously thought, such that petroleum prospectivity for areas including these sequences should be reassessed. Yoshihiro Ujiié is a professor of earth and environmental sciences at Hirosaki University, Japan. He received a B.Sc. degree in geology from the Tokyo University of Education in 1972 and a Ph.D. in geology from Hokkaido University in 1979. His current research interests include diagenetic changes in pollen color and simulation experiments on hydrocarbon generation from living algae and pollen.Neil Sherwood graduated with a B.Sc. honors degree in geology from the University of Manitoba, Canada, in 1977 and with a Ph.D. on organic petrology of oil shales in 1991 from the University of Wollongong, Australia. He has coauthored about 30 journal and conference papers, abstracts, and posters, as well as about 80 unpublished organic petrological reports for industry and research institutions. Mohinudeen Faiz is a research scientist at Commonwealth Scientific and Industrial Research Organisation Petroleum, with his main research interests being coal seam gas and organic petrology. Faiz has been working as a geologist for groundwater exploration, coal seam gas studies, gas outburst studies for coal mines, and petroleum source rock studies. He holds an M.Sc. degree and a Ph.D. from the University of Wollongong, Australia. Ron Wilkins holds a Ph.D. from Cambridge and a D.Sc. from Melbourne University. He has worked on the weathering of minerals, the infrared, Raman, Mossbauer, and fluorescence spectroscopy of minerals, fluid inclusions related to the origin of ore deposits, and most recently carried out research in coal technology and petroleum exploration. He has lectured and researched extensively in France and China.

Description: Remote mapping of surface structures can be conducted by draping digital orthophotos and geologic maps over digital elevation models in geographic information systems. Formational contacts can be mapped by viewing the intersections of these contacts with the topography on a true-to-scale, three-dimensional image. Bedding orientations can be determined from (1) the trends and slopes of dip slopes or (2) best fit planes to multiple points of intersection of a bedding surface with the topography. The methods are tested against mapped formation contacts and bedding attitudes for the Sheep Mountain anticline in the Bighorn basin, Wyoming. Detailed mapping of formation contacts is improved by careful observations of the contacts on three-dimensional images. Interpreted bedding attitudes from slope and multiple-point solutions show strong positive correlations with field measurements. This mapping method provides an efficient and accurate alternative to stereoscopic mapping using aerial photographs and satellite images, particularly for remote and inaccessible areas. Subhotosh Banerjee received his B.Sc. and M.Sc. degrees from Calcutta University and his M.S. degree in geology from the University of Oklahoma (2002). He is currently working toward a Ph.D. in structural geology at the University of Oklahoma. His research interests are in surface and subsurface structural analysis and the application of remote sensing and geographic information systems to structural geology. Shankar Mitra holds the Monnett Chair and Professorship of Energy Resources at the University of Oklahoma. He received his Ph.D. degree from Johns Hopkins University in 1976. His primary research interests are in surface and subsurface structural analysis.

Description: Nonmarine strata of the Lower Cretaceous Mannville Group and marine strata of the Upper Jurassic Ellis Group in southern Alberta were deposited in the low-accommodation, eastern, and distal margin of the Western Canada sedimentary basin. The Manyberries oil field produces hydrocarbons from preserved interfluves as well as the deposits of compound valley fills. These Mannville Group sediments provide an end-member component for nonmarine sedimentation in a low-accommodation setting. The succession is characterized by thin sediment accumulations deposited over a long period of time; multiple unconformities, some profound; incised valleys, typically compound in nature; paleosols of varying degrees and maturity; and a general absence of coal. Dale Leckie is chief geologist at Nexen Inc. He is a specialist in sedimentology, sequence stratigraphy, and basin analysis. He has worked on Australia, Colombia, Yemen, and New Zealand basins. Leckie has received numerous awards from the AAPG, SEPM, and Canadian Society of Petroleum Geologists. He coedited AAPG Memoir 55 entitled Foreland Basins and Fold Belts and Canadian Society of Petroleum Geologists Memoir 15 entitled Sequence StratigWraphy: Surface, Subsurface and Sedimentology. Karen Wallace-Dudley is a scientist at the Geological Survey of Canada, Calgary. She specializes in the sedimentology, stratigraphy, and petroleum geology of Jurassic and Cretaceous hydrocarbon-bearing strata in western Canada. Nancy Vanbeselaere is the principal of Rocky Mountain Consultants. She is a specialist on Mannville stratigraphy of southern Alberta and Saskatchewan. Nancy worked for several years at Imperial Oil Limit and as a consultant at the Geological Survey of Canada. David James is manager of geology at Anadarko Canada; his main interests are exploration, sedimentology, and sequence stratigraphy. He has worked extensively throughout the Western Canada basin, Canada's frontiers, and internationally. He has received awards from the Canadian Society of Petroleum Geologists, AAPG, and SEPM and was coeditor of Canadian Society of Petroleum Geologists Memoirs 15 and 18 on sequence stratigraphy and the Mannville Group.

Description: In the northeastern Gulf of Mexico, Upper Jurassic Smackover inner ramp, shallow-water thrombolite buildups developed on paleotopographic features in the eastern part of the Mississippi Interior Salt basin and in the Manila and Conecuh subbasins. These thrombolites attained a thickness of 58 m (190 ft) and were present in an area of as much as 6.2 km2 (2.4 mi2). Although these buildups have been exploration targets for some 30 yr, new field discoveries continue to be made in this region. Thrombolites were best developed on a hard substrate during a rise in sea level under initial zero to low background sedimentation rates in low-energy and eurytopic paleoenvironments. Extensive microbial growth occurred in response to available accommodation space. The demise of the thrombolites corresponded to changes in the paleoenvironmental conditions associated with an overall regression of the sea. The keys to drilling successful wildcat wells in the thrombolite reservoir play are to (1) use three-dimensional seismic reflection technology to find paleohighs and to determine whether potential thrombolite reservoir facies occur on the crest and/or flanks of these features and are above the oil-water contact; (2) use the characteristics of thrombolite bioherms and reefs as observed in outcrop to develop a three-dimensional geologic model to reconstruct the growth of thrombolite buildups on paleohighs for improved targeting of the preferred dendroidal and chaotic thrombolite reservoir facies; and (3) use the evaporative pumping mechanism instead of the seepage reflux or mixing zone models as a means for assessing potential dolomitization of the thrombolite boundstone. Ernest A. Mancini is regional director of the Eastern Gulf Region of the Petroleum Technology Council, director of the Center for Sedimentary Basin Studies, and professor in petroleum geology in the Department of Geological Sciences at the University of Alabama. His research focus is on reservoir charactertization and modeling, petroleum systems, and the application of stratigraphic analysis to petroleum exploration.Juan Carlos Llinás obtained his B.A degree from the National University of Colombia in 1995 and his M.S. degree in 2003 from the University of Alabama, and he is currently working on his Ph.D. at the University of Alabama. He is studying Smackover oil fields associated with microbial reef buildups and genetically related depositional facies using well and seismic data. William Parcell is an assistant professor in the Department of Geology at Wichita State University. His research integrates sequence stratigraphy, microbial sedimentology, and soft-computing techniques in stratigraphic modeling. He received his B.S. degree (1994) from the University of the South (Sewanee, Tennessee), his M.S. degree (1997) from the University of Delaware, and his Ph.D. from the University of Alabama (2000). Marc Aurell received his B.A. degree (1985) and his Ph.D. (1990) in geology from Zaragoza University. He is currently working at Zaragoza University as a professor. Most of his work in the last 20 years has been concentrated on facies and sequence-stratigraphic analysis of the Mesozoic and Cenozoic carbonate platforms developed in the Iberian basin and in the Pyrenees (Spain). Beatriz Bádenas obtained her B.A. degree (1991) and her Ph.D. (1999) in geology at Zaragoza University, where she teaches courses in stratigraphy and sedimentology. Her major research interests include facies and sequential analysis of carbonate sediments in shallow platform settings. She is currently studying the application of high-resolution sequence stratigraphy and cyclostratigraphy to Upper Jurassic carbonate platform strata of the Iberian basin. Reinhold Leinfelder, paleontologist, carbonate sedimentologist, and basin analyst, specializes in Jurassic reef systems. He received his Diploma degree from the University of Munich in 1980 and his Ph.D. in 1985 and a postdoctoral habil degree in 1989 from the University of Mainz. He was an associate professor at the University of Stuttgart (1989–1998), and he is now a full professor at the University of Munich. Joe Benson is a professor in the Department of Geological Sciences and senior associate dean of the College of Arts and Sciences at the University of Alabama. His research interests lie in carbonate sedimentology and sedimentary petrology. He received a B.A. degree from the College of Wooster and an M.S. degree and a Ph.D. from the University of Cincinnati.

Description: We use established analytical methods and numerical computation techniques to model the net effect on sandstone permeability induced by realistic arrays of low-permeability deformation bands. Our two-dimensional approach, based on homogenization theory, allows the local permeability impact of any deformation band pattern to be calculated and provides a framework within which to extrapolate the effects of systematic patterns to the reservoir-simulation scale. We demonstrate the method for each of three characteristic deformation band patterns—parallel, cross-hatch, and anastomosing—exposed in the Aztec Sandstone at the Valley of Fire, Nevada, which provides an excellent exhumed analog for active sandstone reservoirs. Our analysis indicates that these systematic and extensive deformation band patterns can reduce overall permeability by as much as two orders of magnitude at scales relevant to reservoir production while inducing similar magnitudes of permeability anisotropy. We conclude that accounting for the aggregate effects of deformation bands in the subsurface would significantly improve reservoir simulation and production management in sandstone.

Description: Images of carbonate mound structures in Denmark and Sweden are obtained from ground-penetrating radar (GPR) reflections and outcrop analysis. The GPR data are collected in limestone quarries and provide a depth penetration of about 10 m (33 ft) and a vertical resolution of about 0.5 m (1.6 ft). The mounds are part of the northwest European Upper Cretaceous–Danian (lower Paleocene) Chalk Group, and they are similar to each other in terms of architecture, spatial distribution, and size, with widths and lengths of 30–60 m (100–200 ft) and heights of 5–10 m (16–33 ft). Seismic reflection images from the sea of Kattegat between Sweden and Denmark and the North Sea show large (∼500–1000-m [∼1640–3280-ft]-wide and ∼50–100-m [∼160–330-ft]-high) moundlike carbonate structures. Interpretations of such large mounds conflict with the GPR and outcrop observations. We address these conflicting observations. We construct realistic reference models of carbonate mound complex geometries based on the results of the GPR measurements and outcrop analysis and calculate synthetic seismic sections for the models. The modeling results show that the size of individual mounds is below the seismic resolution of 10–25 m (33–82 ft), and that interference effects caused by stacks of mounds may explain the observed large moundlike structures. Our findings are important for the interpretation of seismic images of carbonate mound structures. Carbonate mound buildups may form traps, and correct seismic interpretation of mound complex geometry may be essential for evaluation of the nature and reservoir potential of such structures. Lars Nielsen received a Ph.D. in geology from Aarhus University, Denmark (1998). Since then, he has worked as an assistant professor at the Geological Institute, University of Copenhagen. His work includes ground-penetrating radar and seismic studies of near-surface geological structures, wavefield modeling, joint inversion of seismic and gravity data, and deep seismic investigation of the crust and upper mantle.Lars Ole Boldreel received a Ph.D. in applied geophysics from Luleå Technical University, Sweden (1988), followed by 10 years with the Geological Survey of Denmark and Greenland. Since 1998, he has been an associate professor at the Geological Institute, University of Copenhagen. His work includes interpretation of seismic reflection data and wire-line logs mainly offshore Faroe Islands, northeast Atlantic. Finn Surlyk received his Ph.D. (1971) and his Dr. Scient. (1978) from the University of Copenhagen. He has been head of the Petroleum Geology Department of the Geological Survey of Greenland and is currently professor of geology at the University of Copenhagen. His interests include sequence stratigraphy, basin analysis, the great period boundaries, Cretaceous carbonates, and Jurassic clastics of the North Atlantic region.

Description: Shale units can be important barriers to fluid flow in sedimentary basins and commonly serve as seals to petroleum reservoirs. Little is known, however, about the controls on shale permeability. Consequently, variation in seal competency is one of the greatest risk factors associated with petroleum exploration. Here, we examine possible controls on sealing capacity in two Cretaceous marine shale units in the Denver basin, Colorado. Sealing capacity, as determined by mercury injection–capillary pressure analysis, is compared to several textural and compositional parameters and to sequence-stratigraphic setting. These two shale units display highly variable sealing capacity, even between some adjacent samples. This suggests that variability in some small-scale shale characteristics may strongly influence sealing capacity. The best seals are generally in transgressive systems tracts, especially within or immediately below condensed sections. Textural characteristics of shale appear to be especially important in determining sealing capacity. In particular, well-sorted pore-throat sizes and well-developed bedding-parallel preferred orientation of flattened organic matter particles strongly favor high sealing capacity. High degrees of bioturbation degrade sealing capacity, possibly by disrupting preferred orientation and by increasing variability in grain size and hence in pore-throat sorting. Preferred orientation of matrix clays parallel to bedding also appears to increase with increasing sealing capacity, but is probably less important than the preferred orientation of organic matter. Compositional characteristics are generally less important than textural characteristics in determining sealing capacity in these shale units. Neither silt content nor cement content appears to be important to sealing capacity in these shale units. Total organic carbon is generally high in samples with good sealing capacity, but can be either high or low where sealing capacity is poor. Overall, the variables that most strongly favor high sealing capacity, pore-throat sorting, organic matter bedding-parallel preferred orientation, and low bioturbation, are most likely in anoxic, deep-water settings, hence, the association between good seals and condensed sections. Sally J. Sutton received a B.S. degree from the University of Michigan and a Ph.D. from the University of Cincinnati. She was a research associate at the University of Texas at Austin and is now an associate professor at Colorado State University. Her research interests include shale petrology and geochemistry, clastic diagenesis, fluid and rock interaction, and chemical weathering.Frank G. Ethridge obtained his B.S. degree from Mississippi State University in 1960, his M.S. degree from Louisiana State University in 1966, and his Ph.D. from Texas A&M University in 1970. He is a full professor of geology at Colorado State University. His present research interests include estimating reservoir shale seal capacity for exploration and risk analysis; testing sequence-stratigraphic concepts using outcrop, subsurface, and experimental data; and formation and architecture of modern and ancient fluvial deposits. William R. Almon earned his Ph.D. in geology from the University of Missouri. He received an M.S. degree in petroleum engineering from Tulsa University and his A.B. degree in chemistry from Washington University (St. Louis). His 29-year career includes positions in research, applied technology, and exploration at Cities Service, Anadarko, Texaco, and ChevronTexaco. His research interests include sequence stratigraphy and fine-grained marine siliciclastic depositional systems, as well as sedimentary geochemistry and diagenesis. W. C. Dawson is a research geologist for ChevronTexaco. He received a Ph.D. in sedimentary petrography (University of Illinois at Champaign-Urbana) in 1984. His work history includes the Illinois Geological Survey, Eason Oil Company, and Texaco Research. His current interests include seal characterization, shale sedimentology, and reservoir diagenesis. He is a member of AAPG, SEPM, and the International Association of Sedimentologists. Kimberly K. Edwards is a water resource consultant for Jehn Water Consultants, Inc. in Denver, Colorado. She received an M.S. degree in geology from Colorado State University in 1999 and previously worked with Texaco Exploration and Production Technology Department (EPTD) as an intern. She is a member of the National Ground Water Association and is a professional geologist in the state of Utah.

Description: Modern depositional settings provide unambiguous geomorphic data facilitating the quantification of geologic interpretations for the numerical characterization of subsurface strata. Traditional three-dimensional geologic descriptions are limited by one- and two-dimensional data sources: generally well and outcrop data. However, geomorphic analyses of fluviodeltaic systems yield size distributions for discrete sedimentary units. These distributions provide constraints for conditioning the area ( X and Y dimensions), shape, placement, and preferred orientation(s) of sedimentary units in reservoir models. Dimensional data for channel belts, channels, channel bars, crevasse splays, distributary channels, and distributary mouth bars from the fluvially dominated deltas of the Alaska North Slope and the Louisiana Gulf Coast reveal log-normal distributions for their lengths and widths. Modern analogs provide statistical constraints for conditioning data input for geologic facies associations in object-based reservoir models. Geomorphic data from modern fluviodeltaic analogs are linked with core and wire-line–log data to render conditioned, three-dimensional geologic models. Model accuracy relies on bed thickness and chronostratigraphic constraints imposed by cores and stratigraphic correlations, as well as the lateral extent of facies associations governed by geomorphology. These object-based reservoir models demonstrate the impact that varying the population of lengths and widths for geologic features has on sand body distribution and interwell continuity. Robert S. (Bo) Tye is a consulting geologist with PetroTel Inc. in Plano, Texas. His interest in sedimentology and depositional systems was piqued during childhood visits to the beach and while exploring the coastal rivers near Charleston, South Carolina. He holds degrees from the College of Charleston, University of South Carolina, University of Alaska, Anchorage, and Louisiana State University. Prior employment, primarily as a reservoir geologist, includes stints at Cities Service Company, the Texas Bureau of Economic Geology, Atlantic Richfield Company (ARCO), and Phillips Petroleum Company. Bo has worked on exploration and development projects in numerous areas including Alaska, Venezuela, Indonesia, and Russia.

Description: Low-permeability reservoirs from the Greater Green River basin of southwest Wyoming are not part of a continuous-type gas accumulation or a basin-center gas system in which productivity is dependent on the development of enigmatic sweet spots. Instead, gas fields in this basin occur in low-permeability, poor-quality reservoir rocks in conventional traps. We examined all significant gas fields in the Greater Green River basin and conclude that they all occur in conventional structural, stratigraphic, or combination traps. We illustrate this by examining several large gas fields in the Greater Green River basin and suggest that observations derived from the Greater Green River basin provide insight to low-permeability, gas-charged sandstones in other basins. We present evidence that the basin is neither regionally gas saturated, nor is it near irreducible water saturation; water production is both common and widespread. Low-permeability reservoirs have unique petrophysical properties, and failure to fully understand these attributes has led to a misunderstanding of fluid distributions in the subsurface. An understanding of multiphase, effective permeability to gas as a function of both varying water saturation and overburden stress is required to fully appreciate the controls on gas-field distribution as well as the controls on individual well and reservoir performance. Low-permeability gas systems such as those found in the Greater Green River basin do not require a paradigm shift in terms of hydrocarbon systems as some have advocated. We conclude that low-permeability gas systems similar to those found in the Greater Green River basin should be evaluated in a manner similar to and consistent with conventional hydrocarbon systems. To date, resource assessments in the Greater Green River basin have assumed a widespread, continuous-type resource distribution. Failure to recognize some of the fundamental elements of low-permeability reservoirs has led to an underappreciation of the risks associated with exploration and development investment decisions in these settings and likely a significant overestimation of available resource levels. Keith W. Shanley is a consulting geologist with more than 22 years experience in exploration, development, and research. He has published numerous papers dealing with sequence stratigraphy and reservoir architecture and has served as editor of several publications. He received his B.A. degree in geology from Rice University and his M.Sc. degree and his Ph.D. in geology from the Colorado School of Mines. His current research interests include sequence stratigraphy and reservoir architecture, the integration of petrophysics, and risk analysis.Bob Cluff is a geologist with 28 years petroleum exploration and development experience. Bob's research interests include the integration of geology with petrophysics and the evaluation of nonconventional reservoirs. Bob received his B.S. in geology from the University of California-Riverside, his M.S. from the University of Wisconsin-Madison, with additional studies at the University of Illinois-Urbana-Champaign, University of Colorado-Denver, and Metropolitan State College Denver in geology, math and physics. Bob founded The Discovery Group in 1987. John W. Robinson is a consulting geologist in Denver and has 30 years of experience in exploration and development. In 1999, he and coauthor Peter McCabe received the AAPG Wallace Pratt Award for the best paper in the 1997 AAPG Bulletin . He received B.S. and M.S. degrees in geology from San Diego State University and a Ph.D. in geology from the Colorado School of Mines. His research interests are in fluvial sedimentology and multidisciplinary reservoir studies.

Description: The General Levalle basin forms a long, narrow, and deep Early Cretaceous intracratonic rift in southern Córdoba province, Argentina. It trends approximately north-south for more than 150 km (93 mi), ranges from 5 to 50 km (3 to 31 mi) wide, and is more than 6500 m (21,325 ft) deep. Below a prominent middle Cretaceous unconformity, steeply dipping normal faults bound tilted graben and half-graben fault blocks. The lower rift-fill section, the General Levalle Formation (new formation name), is a Valanginian–Hauterivian siliciclastic and evaporite package more than 3200 m (10,500 ft) thick. It was deposited in an arid, restricted, rift basin that included a hydrologically closed saline lake. Nine lithology-based members represent one continuous cycle of deposition, with a lower coarse clastic sequence gradually fining upward into an evaporite member and then coarsening upward again to an upper sandstone. The uppermost rift-fill sequence, the Guardia Vieja Basalt (new formation name), is a series of Aptian basalt flows and sills more than 800 m (2625 ft) thick, with some thin red-bed intervals. Unstructured Upper Cretaceous to Pleistocene strata overlie the buried rift basin. Following an extensive exploration campaign, in 1995–1996 the first exploratory well in the basin tested a deep-seated anticline to 5179 m (16,991 ft), but encountered just one minor show. Reservoir-quality sandstone occurred only in the upper rift sandstone member, but this lacked adequate seals. Deeper sandstone beds were tightly cemented, and basin-center dark shale below the evaporite member was thin, surprisingly low in total organic carbon, and overmature for oil. Although additional geological, geophysical, and geochemical work could have improved predrill understanding and risk evaluation, in the end, only drilling the wildcat determined the actual subsurface situation. It is now evident that given the narrow, deep depocenter, unfavorable reservoir-seal relationships, and a paucity of source facies, an effective petroleum system probably never existed in the basin. Robert Webster has a B.S. degree in geology from the University of Colorado (1967) and an M.S. degree from the University of Texas at Arlington (1978). After 16 years of both international and domestic work, Webster joined Hunt Oil Company in 1988 as a senior geologist in international exploration. He has initiated or evaluated frontier exploration plays in virtually every country in Latin America, as well as parts of Africa and the Middle East, and was Hunt's general manager in Argentina in 1993–1994. Webster is past president of the Dallas Geological Society (DGS) and the DGS International Group.Gualter Chebli obtained a master's degree in geologic sciences (1966) and petroleum engineering (1968), and a Ph.D. in geologic sciences (1973) from the University of Buenos Aires. After a career with YPF from 1968 to 1991 as geologist and ultimately exploration contracts manager, he founded the consulting firm Phoenix Oil & Gas S.A. He is professor at the University of Buenos Aires and others, and he is current president of the Asociación Argentina de Geólogos y Geofísicos Petroleros. Fritz Fischer has a B.A. degree and a Ph.D. from the University of California, Santa Barbara. He has taught at the University of Nevada, Reno, the University of California, Santa Barbara, and the University of Texas at Arlington. Since his academic career, he has worked in minerals exploration, consulting petrology and, most recently, well-site geology in Argentina, Portugal, and Madagascar.

Description: The lower Eocene (Ypresian) Sui Main Limestone (Sui Main) is the most prolific gas reservoir in Pakistan south of latitude 29°N. It does not outcrop anywhere in Pakistan. In the Kirthar Range, southern Pakistan, and Punjab platform, the Sui Main's chronostratigraphic equivalent is the Laki Formation, which is a nonreservoir facies. To date, only gas has been encountered in Sui Main, which has recoverable reserves of more than 20 tcf in the 14 discovered fields. The paper describes the subsurface geological setting of Sui Main in a regional context. Facies distribution, based on the study of cores and electric logs, is discussed to establish the depositional environments. On the basis of surface geology and evidence from wells, the limits of Sui Main, as a reservoir, have been delineated. It is a regional lenticular development of porous limestone that is probably isolated on all sides by shales or poor reservoir facies and structural barriers. A subsurface type section of the Sui Main Limestone is designated. To support this geological assumption, a comparative study of original reservoir pressures from different fields and formations has been conducted. It indicates that the Sui Main is an isolated reservoir and not in communication with the surface. On this basis, I conclude that the Sui Main is a closed-system reservoir, having a huge common aquifer system with all the known and unknown hydrocarbon fields perched at different hydrostatic levels. Being a closed-system reservoir, the gas pools are expected to experience weak aquifer support during the producing life of the fields. This phenomenon has so far been observed in fields that are in a mature stage of production like Sui field. The area of the common aquifer, the reservoir-quality rock volume, and the cumulative voidage (pore space) that could be present in Sui Main and could contain hydrocarbons and water have also been computed and delineated. Nusrat Kamal Siddiqui joined Pakistan Petroleum Limited in February 1981 and is presently designated as senior manager of exploration. He obtained his B.Sc. (hons.) and M.Sc. degrees in 1969 from the Geology Department, Punjab University, Lahore, Pakistan, specializing in petroleum and structural geology. In 1979–1980, he completed a postgraduate diploma course related to photogeology and remote sensing, with emphasis on hydrogeology from International Training Center, Netherlands. Nusrat has over 33 years of diversified experience in engineering geology for working on earth fill dams (1970–1975), hydrogeology with the Ministry of Agriculture, Government of Libya (1975–1979), and hydrocarbon exploration (1980 to present). His interests involve log evaluation, field studies/geological modeling of reservoirs, field geology, remote-sensing applications, and prospect generation. He has published papers on petroleum exploration, field development, and remote-sensing applications to petroleum geology and flood control. He is an active member of AAPG, Pakistan Institute of Petroleum, and a founding member of the Pakistan Association of Petroleum Geoscientists (PAPG, an affiliate of AAPG). He was the chairman of the Technical Program Committee for the PAPG-Society of Petroleum Engineers Annual Technical Conference (ATC) and Oil Show 2002 and the chairman and organizer of ATC and Oil Show 2003, October 3–5, 2003, both held in Islamabad, Pakistan.

Description: High-resolution geophysical data were acquired for an investigation across a portion of Sigsbee Escarpment using an autonomous underwater vehicle (AUV Hugin 3000), which allowed mapping of the seabed and near-seafloor features in detail and large two-dimensional data sets to be collected in a short time in deep water over rugged terrain. Complex seafloor structures are revealed in the survey area. These seafloor structures include a graben fault zone, rugged escarpment faces, slump deposits, and erosional furrows. Geological morphologies occurring in the survey area are associated with salt tectonics, gravitational driven failure, and ocean bottom-current activities. The Sigsbee Escarpment in the survey area is marked by an abrupt scarp on the order of 700 m (2300 ft) and a prominent increase in seafloor gradients as much as 30°. The Sigsbee Escarpment in the center and west of the survey area is generally scalloped, representing retrogressive slumps. The escarpment face is characterized by narrow and sharp ridges and numerous gullies. In the east of the survey area, the escarpment appears to be upturned, tilted, and eroded. A graben fault structure, representing a suture zone possibly associated with the joining of the two underlying salt sheets, is observed in the north-central survey area. In front of the escarpment, on the continental rise, a series of longitudinal furrows and slump deposits have been interpreted. The slump deposits at the base of the escarpment form aprons of sediment consisting of displaced and mixed sediments primarily of clay. Y.-D. Eddy Lee is currently working as a geologist at C&C Technologies, Inc., where he started in 1999. He received his M.S. degree (1995) and his Ph.D. (2000) in geological oceanography from Texas A&M University and his B.S. degree in geology from Chinese Culture University in Taiwan (1988). His areas of interest and specialization include the study of marine geologic hazards and the geotechnical engineering properties of soils.Robert A. “Tony” George is the geosciences manager at C&C Technologies, Inc. He holds B.S. degrees in geophysics (1985) from the University of Louisiana, Monroe, and computer science from Louisiana Tech University (1988). He has been involved with the acquisition and interpretation of high-resolution, marine geophysical survey data for more than 15 years. Tony is a 20-year member of the AAPG.

Description: Conventional cores from Lower Cretaceous outer-shelf and upper-slope prodelta facies in the Alma and Glenelg fields of the Scotian Basin show a wide range of synsedimentary deformation. Storm-dominated prodelta sandstone and mudstone beds have common load casts and structureless sandstone beds overlain by deformed sediment and sandstone dykes that are caused by storm- or earthquake-induced local liquefaction. Blocks of sediment 5–15 m (15–50 ft) thick, principally on the outer shelf, have foliated mudstone at their base, common internal shear zones in mudstone, shear deformation of sandstone, and are capped by intraclast conglomerates that are interpreted as debris-flow deposits. These are all features observed in shallow slides on the modern Mississippi prodelta. At the paleoshelf edge and upper slope, larger slide blocks are recognized with zones of intense internal deformation and high-angle thrusts near their base. The lack of a basal foliated mudstone may be the result of more rapid slide motion than on the shelf, resulting in hydroplaning. In addition, there is early postdepositional interstratal deformation as a result of loading by sandy delta distributaries and by slide blocks on the upper slope. The scale of many deformation structures is below the limits of three-dimensional seismic vertical resolution, yet they are likely to substantially influence reservoir properties. David J. W. Piper obtained his B.Sc. degree and his Ph.D. from the University of Cambridge, United Kingdom. After a decade of teaching at Dalhousie University, he joined the Geological Survey of Canada as a marine geologist, presently working on deep-water geohazards offshore southeast Canada. He has a long-standing interest in the application of insights from the marine realm to ancient sedimentary successions.Georgia Pe-Piper graduated from the University of Athens, Greece, and gained her Ph.D. in volcanic geochemistry from the University of Cambridge, United Kingdom. She is best known for work on igneous rocks, but for many years, her teaching responsibilities included petroleum geology. Her current interests include the application of mineralogical studies to the provenance and diagenesis of sedimentary systems. Steve Ingram graduated with an honors B.Sc. with the Co-operative Education option degree in geology in 2002 from Saint Mary's University, Nova Scotia. His thesis was on the Alma and Glenelg fields. Since then, he has been working as a geoscientist for ChevronTexaco in Canadian Frontier Exploration. Areas of interest include offshore Newfoundland, Nova Scotia, and the Beaufort Sea/Mackenzie delta region.

Description: During a geohazards evaluation of an area in deep-water Green Canyon, using standard exploration three-dimensional (3-D) seismic data, different features of significance to drilling operations and the planning of seabed installations were observed. These features were indications of seabed slope instability, shallow gas accumulations in a channel deposit, gas chimneys, faults, and a seabed mound above a gas chimney. Edge-detection maps were used to highlight slope-failure scars, faults, the channel, and the seabed mound. Average absolute-amplitude maps were used to highlight slope-failure scars, faults, and possible shallow gas accumulations. Possible gas chimneys were mapped to identify fluid-migration pathways. The mapping of chimneys was done by the use of a recently developed method for detection of gas chimneys in 3-D seismic data. The method was developed to facilitate and increase the consistency in the mapping, as well as make gas chimneys visible in the map view. The results of the geohazards assessment were identification of a seabed slope-failure risk and a risk of overpressured gas in channel deposits. Roar Heggland is a geophysicist with Statoil ASA in Stavanger, Norway. He joined Statoil in 1984 and has worked as a seismic interpreter in exploration, research, and technology applications with specific focus on geohazards and fluid flow. He is coinventor of the method for detection of gas chimneys in 3-D seismic data. Roar Heggland holds a degree in particle physics from the University of Bergen, Norway.

Description: Will Sager is a professor in the Departments of Oceanography and Geology and Geophysics and is the holder of the Jane and R. Ken Williams '45 Chair in Ocean Drilling Science, Technology, and Education at Texas A&M University. He received a Ph.D. in geology and geophysics at the University of Hawaii and has spent the last 20 years at Texas A&M teaching and researching marine geology and geophysics. Author of 75 refereed research papers, and advisor of 20 M.S. and Ph.D. graduates, he has participated in 36 oceanographic research cruises.William Bryant is a professor of oceanography. He received an M.S. degree and a Ph.D. at the University of Chicago. He has spent the last 40 years at Texas A&M University teaching and doing research in marine geology, high-resolution marine geophysics, and marine geotechnology. He was head of the Department of Oceanography from 1998 to 2000. He has worked in the Gulf of Mexico, Caribbean, West Africa, the Arctic and Antarctic, and sailed all five of the Russian Polar Seas. He is the author of over 300 papers, co-editor of 1 book, and advisor of over 100 M.S. and Ph.D. graduates. He was co-chief scientist on Deep-Sea Drilling Program Leg 10, and scientist on Leg 96 and Ocean Drilling Program Legs 113 and 121. Earl Doyle is an engineering consultant specializing in marine geoscience and geotechnical foundation design for marine structures. He received an M.S. degree in ocean engineering from the University of Rhode Island and is retired from Shell Oil Company where he was last involved in deep-water geohazard studies and the design of foundations for tension leg platforms. He authored or coauthored 47 papers and is a member of the Ocean Studies Board and the U.S. Science Advisory Committee for the Integrated Ocean Drilling Program. Today is a wonderful …

Description: The three-dimensional, interwell-scale architecture of a Lower Ordovician Ellenburger coalesced, collapsed-paleocave system was constructed through the integration of ground-penetrating radar (GPR), shallow-core, and outcrop data. The data were collected near Marble Falls in central Texas over an area (∼800 × 1000 m [∼2600 × 3300 ft]) that could cover several oil-well locations (∼160 ac; 0.65 km2) typical of a region such as west Texas. Integration of core-based facies descriptions with GPR-reflection response identified several paleocave facies that can be recognized and mapped with GPR data alone: (1) continuous reflections image the undisturbed strata, (2) relatively continuous reflections (over tens of meters) characterized by faults and folds image the disturbed strata, and (3) chaotic reflections having little to no perceptible continuity image heterogeneous, cave-related brecciated facies recognized in core that cannot be individually resolved with the GPR data. These latter facies include the highly disturbed strata, coarse-clast chaotic breccia, fine-clast chaotic breccia, and sediment fill. The three-dimensional architecture of the coalesced, collapsed-paleocave system based on core and GPR data indicates that there are trends of brecciated bodies that are as much as 350 m (1100 ft) wide, greater than 1000 m (3300 ft) long, and tens of meters high. These brecciated bodies are coalesced, collapsed paleocaves. Between the brecciated bodies are areas of disturbed and undisturbed host rock that are jointly as much as 200 m (660 ft) wide. As a cave system is buried, many structural features form by mechanical compaction. These features include folds, sags, and faults. The folds and sags measure from a few meters to several hundred meters wide. The collapse-related faults are numerous and can have several meters of displacement. Most are normal faults, but reverse faults also occur. Robert Loucks obtained his B.A. degree from the State University of New York, Binghamton, in 1967 and his Ph.D. from the University of Texas at Austin in 1976. He is a senior research scientist at the Bureau of Economic Geology, working on carbonate and siliciclastic reservoir characterization research. His major interests include sequence stratigraphy, depositional systems, and diagenesis of both carbonates and siliciclastics.Paul Mescher is a principal consulting geologist for Veritas Exploration Services in Houston, Texas. He has more than 22 years of diverse geological experiences, including prospect generation, field extension and development, and reservoir characterization from many areas of the United States and several countries, including the former Soviet Union, Saudi Arabia, Syria, offshore China, Tunisia, Mexico, and Canada. He is author or coauthor of 13 papers. George McMechan received a B.A.Sc. degree in geophysical engineering from the University of British Columbia in 1970 and an M.Sc. degree in geophysics from the University of Toronto in 1971. He is a professor at the University of Texas at Dallas. His main research interests are wavefield imaging, three-dimensional seismology, reservoir characterization, and ground-penetrating radar.

Description: Controls on oil family distribution in tectonically complicated, nonmarine, petroliferous basins are commonly difficult to isolate because of the varying ages of potential source rocks, the complex assemblage of organic-rich sedimentary facies, and the geographic variability of burial histories. The Turpan-Hami basin of northwestern China is an oil-bearing intermontane basin where stratigraphic, sedimentologic, and geochemical controls are sufficient to address each of these issues independently and to determine how they influence the current distribution and composition of liquid hydrocarbons. Source rock age is one of three major statistically significant discriminators affecting oil family composition. Both Lower/Middle (Lower or Middle) Jurassic and Upper Permian rocks are important source rocks for the basin. A newly developed diterpane biomarker parameter can distinguish Permian rocks and their correlative oils from Jurassic coals and mudrocks and their derivative oils. Source facies is a second key control on petroleum occurrence and character. A variety of biomarker parameters that reflect source rock depositional conditions are indexed to rock samples from interpreted depositional environments. By erecting rock-to-oil correlation models, the biomarker parameters separate oil families into end-member groups: group 1 oils = Lower/Middle Jurassic peatland/swamp facies (high land-plant input, less reducing conditions), group 2 oils = Lower/Middle Jurassic profundal lacustrine facies (high algal input, more reducing conditions), and group 3 oils = Upper Permian lacustrine facies (high algal, stratified, anoxic conditions). Burial history exercises a third major control on petroleum distribution. Source rock maturation modeling can demonstrate that relatively uninterrupted burial in the asymmetrically subsiding northern Turpan-Hami area (Taibei depression) exhausted Upper Permian-sourced rocks by the Late Cretaceous, which led to southward migration of Upper Permian–sourced oils (group 3) into Triassic reservoirs of southern and southwestern Turpan-Hami (Tainan and Tokesun depressions). Subsequent to uplift of the central basin thrust that currently partitions Taibei from Tainan, Lower/Middle Jurassic–sourced oils were expelled in the Taibei depression by Paleocene–Eocene time, which locally charged Jurassic and Cretaceous reservoirs (groups 1 and 2), forming Turpan-Hami's largest oil accumulations in the basin. Todd attained a B.S. degree in earth sciences from the University of California at Santa Cruz (1994) and a Ph.D. in geological sciences at Stanford University (2000). His dissertation focused on tectonics, sedimentology, organic geochemistry, and petroleum systems of the Turpan-Hami basin of northwestern China. He is currently employed by Anadarko Petroleum, in Houston, Texas, where he is part of a basin studies team investigating basins and play types in the greater Rocky Mountains, as well as international arenas in southeast Asia.David A. Zinniker is a Ph.D. candidate in the Department of Geological and Environmental Sciences at Stanford University. His research focuses on molecular fossils of plants and algae and their bearing on ecology, evolution, depositional systems, and petroleum geology. His future projects include using molecular and macromolecular markers to study current ecological processes and events deep in geologic time. J. Michael Moldowan attained a B.S. degree in chemistry from Wayne State University in 1968 and a Ph.D. in chemistry from the University of Michigan in 1972. Following a postdoctoral fellowship in marine natural products with Carl Djerassi at Stanford University, he joined Chevron's Biomarker Group in 1974. Moldowan joined the Department of Geological and Environmental Sciences of Stanford University as professor (research) in 1993. Cheng Keming received his degree from China Geology University in 1958. He is currently a senior geologist and professor for the Research Institute of Petroleum Exploration and Development for the China National Petroleum Corporation. He specializes in coal-generating geochemistry and petroleum resource evaluation. Su Aiguo received his degrees from the Jianghan Petroleum University (currently named Yangtze University) in 1986 and the Graduate School of the Research Institute of Petroleum Exploration and Development of the China National Petroleum Corporation in 1989. He worked as a petroleum engineer for the China National Petroleum Corporation and is currently a senior geologist at the Research Institute of Petroleum Exploration and Development of PetroChina. He specializes in petroleum geochemistry.

Description: The concept of rock fabric has been shown to be very useful for characterization of carbonate reservoirs. This study shows that a Pickett crossplot of interparticle porosity vs. true resistivity (in some cases, apparent resistivity or true resistivity affected by a shale group) should result in a straight line for intervals with a constant rock fabric. The slope of the straight line is related to the porosity exponent m , the water saturation exponent n , and the size of the particles forming the interparticle porosity. Different slopes are obtained for different rock fabrics. The method helps to reconcile geology to fluid flow by illustrating the important link between geology, petrophysics, and reservoir engineering. Lines of constant rock fabric are displayed on a Pickett plot, together with water saturation, permeability, process speed k /ϕ, capillary-pressure curves, pore-throat apertures r 35 and r p35, Kozeny's constant ( F sτ2), and height above the free-water table. Pattern recognition while placing all these data in a consistent form on a Pickett plot allows determination of flow units and a more rigorous characterization of carbonate reservoirs. The method is aimed at heterogeneous carbonate reservoirs, which have a limited amount of hard data. The use of this technique is illustrated with data from the Mission Canyon Formation in the Little Knife field of North Dakota, where a significant volume of oil in place is below the structural closure and updip wells penetrate microports that provide an effective seal in this stratigraphic trap. Roberto Aguilera is president of Servipetrol Ltd. in Calgary, Canada and an adjunct professor in the Chemical and Petroleum Engineering Department at the University of Calgary, where he concentrates in teaching about the theoretical and practical aspects of naturally fractured reservoirs. He is a petroleum engineering graduate from the Universidad de America at Bogota, Colombia, and holds a master's degree and a Ph.D. in petroleum engineering from the Colorado School of Mines. He was an AAPG instructor on the subject of naturally fractured reservoirs from 1984 to 1996. He has presented his course on naturally fractured reservoirs and has rendered consulting services throughout the world. He is a Distinguished Author of the Journal of Canadian Petroleum Technology (1993 and 1999), a recipient of the Outstanding Service Award from the Petroleum Society of the Canadian Institute of Mining, Metallurgy, and Petroleum Engineers (CIM) in 1994, and a Society of Petroleum Engineers Distinguished Lecturer on the subject of naturally fractured reservoirs for 2000–2001.

Description: The Benguela Current system, running off southwest Africa, is one of the world's largest upwelling regions. The current has strongly influenced sedimentary features on the continental margin. To unravel its development, seismic stratigraphy, tied to drilling results from Ocean Drilling Program Leg 175 sites 1085–1087, was established. Four units, Southern Cape Basin (SCB)-1 to SCB-4, were defined for the Cenozoic sediments. The upper unit, SCB-1 (〈1.5 Ma), characterized by continuous high-amplitude reflectors, represents global cooling and glacial-interglacial cycles. Unit SCB-2 (〈14 Ma), distinguished by low-amplitude reflections, is associated with the onset of the upwelling system and establishment of the modern circulation pattern in the Cape Basin. Slump scarps are concentrated along the middle and upper shelf slope, suggesting they are caused by a combination of mass movements triggered by bottom currents and slope instabilities because of increased deposition associated with the upwelling. A westward extension and/or movement of upwelling filaments is interpreted from the observed seaward shift of scarp locations with time. Erosion associated with stronger currents probably thinned unit SCB-2 in the south. The two lower units, SCB-3 and SCB-4 (〈56 Ma), probably represent material eroded from the shelf break and deposited during a major Oligocene–early Miocene regression that is consistent with a significant uplift of southern Africa. The basal reflector SCB-D of unit SCB-4 is associated with the prominent reflector D or L described in previous publications. After receiving her diploma in geophysics, geology, mineralogy, and physics at J. W. Goethe University in Frankfurt (1989), Estella Weigelt joined the Alfred Wegener Institute (AWI). After an overwintering campaign in the Antarctic advising a geophysical observatory for 14 months, she worked on her Ph.D. on seismic and gravity investigations of the Eurasian Basin. Since then, she has specialized on climate signals in marine sediments recorded in reflection seismics.After receiving her diploma in geophysics, physical oceanography, geology, and physics at Hamburg University (1985), Gabriele Uenzelmann-Neben went to Kiel University and started working toward her Ph.D. on high-resolution seismic reflection investigations of the Voring Margin. In 1989, Uenzelmann-Neben joined AWI and has since specialized on sediment transport, sediment drifts, and obstacles for oceanic currents such as oceanic plateaus and ridges.

Description: The evaluation of a new method based on the integration of geochemical, morphological, and structural analyses for the study of neotectonics in clay basins is presented. More than 900 helium soil-gas samples were collected over an area located in the central sector of the Adriatic foredeep (central Italy). Soil-gas distribution has been compared with the location and orientation of the main structural features described in the literature and/or characterized by field surveys and morphotectonic features obtained by air-photo interpretation and drainage network analysis. Collected data were statistically analyzed and compared by means of rose diagram plots. A geostatistical approach was used to describe the spatial behavior of the helium distribution. The comparison of the morphological and structural elements with the observed geochemical anomalies shows that the northwest-southeast is the most representative direction in agreement with the known Apennine structural trends. Moreover, the presence of north-south and east-west trends in the helium regional distribution, observed in the central and southern sectors of the studied area, is thought to be caused by a more recent deformation phase acting along these directions. This hypothesis is strengthened by the good correspondence, both at regional and local scales, between geochemical data and the results of the structural and geomorphological analyses. Furthermore, the magnitude and the anisotropic distribution of the helium anomalies in the residual maps indicate that at local scale, this gas could be related with the distribution of the hydrocarbon reservoirs occurring in the area. Giancarlo Ciotoli has been associated with the Earth Science Department of Rome University since 1990. He has accumulated experience in air-photo interpretation, structural geology, and geochemistry. Recently, he has specialized in the application of statistical and geostatistical methods with geographic information systemsoftware for better interpreting spatially distributed geological data. He has been a professor of environmental geochemistry at Calabria University since 1998.Salvatore Lombardi is head of the Fluid Chemistry Laboratory in the Earth Sciences Department of Rome University. He was the founder of the soil-gas method in Italy and has spent the last 30 years researching many aspects of fluid chemistry in various geological environments to understand better subsurface processes that involve gas generation, migration, and accumulation. He is a member of the Italian Geological Society and the American Geophysical Union. Sergio Morandi earned his degree in geology (first class honors) at “La Sapienza” University in Rome. He has 22 years of experience in oil and gas exploration and geophysics and seismic data acquisition and interpretation with Ente Nazionale Idrocarburi, Elf and Enterprise Oil as chief geophysicist. At present, he is the head of exploration in Shell Italia E&P SpA. Since 1997, he has been lecturer of applied seismology at Basilicata University and, since 2002, has been a board member of the Italian National Upstream Association. Francesco Zarlenga earned his degree in geological science at “La Sapienza” University in Rome. He is a researcher at the National Agency for Energy and Environment in the field of environmental geology. He has published 85 papers on geology and environmental geology. He is president of the European Association for the Conservation of the Geological Heritage and a member of the Executive Committee of the Italian Society for Environmental Geology.

Description: This case study of the San Andres Formation in the mature Vacuum field, New Mexico, shows how seismic data can be used to target bypassed pay with horizontal wells. These dual-lateral wells were the first attempt at horizontal development in the Vacuum San Andres field and in the San Andres Formation in New Mexico. The primary reservoir facies consist of ramp crest and outer ramp dolomitized peloidal packstones, skeletal and ooid grainstones, and fusulinid packstones. Vertical facies successions form numerous high-frequency carbonate depositional cycles and cycle sets that create distinct reservoir zones. Structural blocks created by small-scale faults (≤25 ft [8 m] vertical displacement) and bypassed pay located in thin depositional cycles were identified with three-dimensional compressional-wave seismic amplitude and coherency volumes and well data and targeted using medium-radius horizontal wells. Horizontal wells penetrated fault blocks and depositional cycles that were not adequately drained by existing vertical wells. Production curves show a significant increase in production from the horizontal wells and no interference with production from offset vertical wells. This suggests that the faults are partially sealing. Matt Pranter is an assistant professor of geological sciences at the University of Colorado at Boulder. He received a B.S. degree in geology from Oklahoma State University (1987), an M.S. degree in geology from Baylor University (1989), a B.S. degree in geological engineering from the Colorado School of Mines (1996), and a Ph.D. in geology from the Colorado School of Mines (1999). He currently serves as an AAPG associate editor, is a member of the AAPG Distinguished Lecture Committee and is a past member of the AAPG Foundation Grants-in-Aid Committee. He was previously a senior research geologist with ExxonMobil Upstream Research Company and a geologist with Conoco Inc. His research interests are in reservoir geology and geophysics, sedimentary geology, and reservoir modeling. He is a member of AAPG, SEPM, Society of Exploration Geophysicists, Society of Petroleum Engineers, Geological Society of America, European Association of Geoscientists and Engineers, and Society of Petrophysicists and Well Log Analysts.Neil Hurley is a professor of geology at the Colorado School of Mines. He received B.S. degrees in geology and petroleum engineering from the University of Southern California (1976), an M.S. degree in geology from the University of Wisconsin, Madison (1978), and a Ph.D. in geology from the University of Michigan (1986). He is a past editor of AAPG and has been an AAPG distinguished lecturer. Specialties include carbonate geology and reservoir characterization. He is a member of AAPG, Society of Petroleum Engineers, Society of Exploration Geophysicists, SEPM, European Association of Geoscientists and Engineers, and Society of Petrophysicists and Well Log Analysts. Tom Davis is currently a professor of geophysics at the Colorado School of Mines and has 29 years of teaching and research experience. He is the founder and codirector of the Reservoir Characterization Project, an industry-funded consortium in its 18th year of applying multicomponent seismic data to improve hydrocarbon recovery. He holds a Ph.D. in geophysical engineering from the Colorado School of Mines, an M.Sc. degree in geophysics from the University of Calgary, and a B.E. degree in geological engineering (geophysics option) from the University of Saskatchewan. Memberships include AAPG, Canadian Society of Exploration Geophysicists, Denver Geophysical Society, European Association of Geoscientists and Engineers, Rocky Mountain Association of Geologists, and Society of Exploration Geophysicists. Michael Raines is a geologist with Kinder Morgan CO2 Company, L.P. He has a B.S. degree in geology from West Texas State University and an M.S. degree in geology from the University of Oklahoma. His professional interests include reservoir characterization, tertiary recovery, horizontal drilling, earth science education, multicomponent seismic, time-lapse seismic monitoring, and carbonate systems. He is involved with AAPG, West Texas Geological Society, and Permian Basin Section-SEPM. Scott Wehner is a senior engineer with Kinder Morgan CO2 Company, L.P. located in Midland, Texas. He was previously with Texaco. His 22-year career has been in the Permian basin of west Texas and southeast New Mexico. His past 18 years have been devoted to the design, implementation, and/or management of CO2 projects. He has published various CO2-related papers and has one CO2 process patent. He is a past director of the Society of Petroleum Engineers and is a past Department of Energy Program Manager. He graduated from the University of Missouri, Rolla in 1980 with a B.Sc. degree in geological engineering.

Description: Techniques for detection, evaluation, and prediction of pore pressures in low-permeability rocks and equations for fluid-pressure computations in most integrated basin-modeling software are based on relationships between porosity and effective stress in shales. However, recent data show that overpressured shales in the North Sea do not exhibit higher porosities than the normally pressured shales of the same formation at similar depths. To further evaluate the existence of porosity vs. effective stress relationships in shales, fluid-flow simulations and porosity modeling in a typical high-pressure and high-temperature well in the North Sea were undertaken. The parameters in the permeability and porosity equations were adjusted until a satisfactory fit was achieved between the observed and modeled porosity and fluid pressure at present. However, the modeled porosity and pore pressure vs. depth history of the sediments deviated significantly from known porosity and pore pressure vs. depth relationships that have been observed in North Sea shales and elsewhere today. Because the results from basin modeling based on porosity-stress relationships were unacceptable, irrespective of parameter choices, and the well data from the North Sea show no signs of elevated porosities in the overpressured shales, it is inferred that effective stress-driven compaction alone has not generated the hard overpressures observed in deeply buried North Sea shales. These conclusions are suggested to be generally applicable to shales with low porosities and hard overpressures worldwide, both because of the physics involved and because similar results can be extracted from published modeling in the Niger Delta. Hege M. Nordgård Bolås received her M.Sc. degree in petroleum geology from the Norwegian Institute of Technology in Trondheim. She joined Esso Norge A.S. in Stavanger, Norway, in 1985 and worked there as an explorationist until 1992. Her research work includes basin modeling at the Institute for Continental Shelf Research in Trondheim from 1992 until 1994, and since then she has worked on hydrocarbon trapping mechanisms at Statoil's Research Center.Christian Hermanrud is currently project leader at Statoil's Research Center. He has an M.Sc. degree in applied mathematics from the University of Bergen, Norway, and a Ph.D. in geological sciences from the University of South Carolina, Columbia. His background includes 20 years of hydrocarbon exploration and exploration-related research. Gunn M. G. Teige received her M.Sc. degree in 1990 in petroleum geology from the Norwegian Institute of Technology in Trondheim, Norway. She joined Statoil in 1991 and worked as an explorationist and petrophysicist for three years before joining Statoil's Research Center in 1994. Her major research interests are sealing analysis and leakage processes.

Description: Techniques for detection, evaluation, and prediction of pore pressures in low-permeability rocks and equations for fluid-pressure computations in most integrated basin-modeling software are based on relationships between porosity and effective stress in shales. However, recent data show that overpressured shales in the North Sea do not exhibit higher porosities than the normally pressured shales of the same formation at similar depths. To further evaluate the existence of porosity vs. effective stress relationships in shales, fluid-flow simulations and porosity modeling in a typical high-pressure and high-temperature well in the North Sea were undertaken. The parameters in the permeability and porosity equations were adjusted until a satisfactory fit was achieved between the observed and modeled porosity and fluid pressure at present. However, the modeled porosity and pore pressure vs. depth history of the sediments deviated significantly from known porosity and pore pressure vs. depth relationships that have been observed in North Sea shales and elsewhere today. Because the results from basin modeling based on porosity-stress relationships were unacceptable, irrespective of parameter choices, and the well data from the North Sea show no signs of elevated porosities in the overpressured shales, it is inferred that effective stress-driven compaction alone has not generated the hard overpressures observed in deeply buried North Sea shales. These conclusions are suggested to be generally applicable to shales with low porosities and hard overpressures worldwide, both because of the physics involved and because similar results can be extracted from published modeling in the Niger Delta. Hege M. Nordgård Bolås received her M.Sc. degree in petroleum geology from the Norwegian Institute of Technology in Trondheim. She joined Esso Norge A.S. in Stavanger, Norway, in 1985 and worked there as an explorationist until 1992. Her research work includes basin modeling at the Institute for Continental Shelf Research in Trondheim from 1992 until 1994, and since then she has worked on hydrocarbon trapping mechanisms at Statoil's Research Center.Christian Hermanrud is currently project leader at Statoil's Research Center. He has an M.Sc. degree in applied mathematics from the University of Bergen, Norway, and a Ph.D. in geological sciences from the University of South Carolina, Columbia. His background includes 20 years of hydrocarbon exploration and exploration-related research. Gunn M. G. Teige received her M.Sc. degree in 1990 in petroleum geology from the Norwegian Institute of Technology in Trondheim, Norway. She joined Statoil in 1991 and worked as an explorationist and petrophysicist for three years before joining Statoil's Research Center in 1994. Her major research interests are sealing analysis and leakage processes.

Description: This case study of the San Andres Formation in the mature Vacuum field, New Mexico, shows how seismic data can be used to target bypassed pay with horizontal wells. These dual-lateral wells were the first attempt at horizontal development in the Vacuum San Andres field and in the San Andres Formation in New Mexico. The primary reservoir facies consist of ramp crest and outer ramp dolomitized peloidal packstones, skeletal and ooid grainstones, and fusulinid packstones. Vertical facies successions form numerous high-frequency carbonate depositional cycles and cycle sets that create distinct reservoir zones. Structural blocks created by small-scale faults (≤25 ft [8 m] vertical displacement) and bypassed pay located in thin depositional cycles were identified with three-dimensional compressional-wave seismic amplitude and coherency volumes and well data and targeted using medium-radius horizontal wells. Horizontal wells penetrated fault blocks and depositional cycles that were not adequately drained by existing vertical wells. Production curves show a significant increase in production from the horizontal wells and no interference with production from offset vertical wells. This suggests that the faults are partially sealing. Matt Pranter is an assistant professor of geological sciences at the University of Colorado at Boulder. He received a B.S. degree in geology from Oklahoma State University (1987), an M.S. degree in geology from Baylor University (1989), a B.S. degree in geological engineering from the Colorado School of Mines (1996), and a Ph.D. in geology from the Colorado School of Mines (1999). He currently serves as an AAPG associate editor, is a member of the AAPG Distinguished Lecture Committee and is a past member of the AAPG Foundation Grants-in-Aid Committee. He was previously a senior research geologist with ExxonMobil Upstream Research Company and a geologist with Conoco Inc. His research interests are in reservoir geology and geophysics, sedimentary geology, and reservoir modeling. He is a member of AAPG, SEPM, Society of Exploration Geophysicists, Society of Petroleum Engineers, Geological Society of America, European Association of Geoscientists and Engineers, and Society of Petrophysicists and Well Log Analysts.Neil Hurley is a professor of geology at the Colorado School of Mines. He received B.S. degrees in geology and petroleum engineering from the University of Southern California (1976), an M.S. degree in geology from the University of Wisconsin, Madison (1978), and a Ph.D. in geology from the University of Michigan (1986). He is a past editor of AAPG and has been an AAPG distinguished lecturer. Specialties include carbonate geology and reservoir characterization. He is a member of AAPG, Society of Petroleum Engineers, Society of Exploration Geophysicists, SEPM, European Association of Geoscientists and Engineers, and Society of Petrophysicists and Well Log Analysts. Tom Davis is currently a professor of geophysics at the Colorado School of Mines and has 29 years of teaching and research experience. He is the founder and codirector of the Reservoir Characterization Project, an industry-funded consortium in its 18th year of applying multicomponent seismic data to improve hydrocarbon recovery. He holds a Ph.D. in geophysical engineering from the Colorado School of Mines, an M.Sc. degree in geophysics from the University of Calgary, and a B.E. degree in geological engineering (geophysics option) from the University of Saskatchewan. Memberships include AAPG, Canadian Society of Exploration Geophysicists, Denver Geophysical Society, European Association of Geoscientists and Engineers, Rocky Mountain Association of Geologists, and Society of Exploration Geophysicists. Michael Raines is a geologist with Kinder Morgan CO2 Company, L.P. He has a B.S. degree in geology from West Texas State University and an M.S. degree in geology from the University of Oklahoma. His professional interests include reservoir characterization, tertiary recovery, horizontal drilling, earth science education, multicomponent seismic, time-lapse seismic monitoring, and carbonate systems. He is involved with AAPG, West Texas Geological Society, and Permian Basin Section-SEPM. Scott Wehner is a senior engineer with Kinder Morgan CO2 Company, L.P. located in Midland, Texas. He was previously with Texaco. His 22-year career has been in the Permian basin of west Texas and southeast New Mexico. His past 18 years have been devoted to the design, implementation, and/or management of CO2 projects. He has published various CO2-related papers and has one CO2 process patent. He is a past director of the Society of Petroleum Engineers and is a past Department of Energy Program Manager. He graduated from the University of Missouri, Rolla in 1980 with a B.Sc. degree in geological engineering.

Description: The concept of rock fabric has been shown to be very useful for characterization of carbonate reservoirs. This study shows that a Pickett crossplot of interparticle porosity vs. true resistivity (in some cases, apparent resistivity or true resistivity affected by a shale group) should result in a straight line for intervals with a constant rock fabric. The slope of the straight line is related to the porosity exponent m , the water saturation exponent n , and the size of the particles forming the interparticle porosity. Different slopes are obtained for different rock fabrics. The method helps to reconcile geology to fluid flow by illustrating the important link between geology, petrophysics, and reservoir engineering. Lines of constant rock fabric are displayed on a Pickett plot, together with water saturation, permeability, process speed k /ϕ, capillary-pressure curves, pore-throat apertures r 35 and r p35, Kozeny's constant ( F sτ2), and height above the free-water table. Pattern recognition while placing all these data in a consistent form on a Pickett plot allows determination of flow units and a more rigorous characterization of carbonate reservoirs. The method is aimed at heterogeneous carbonate reservoirs, which have a limited amount of hard data. The use of this technique is illustrated with data from the Mission Canyon Formation in the Little Knife field of North Dakota, where a significant volume of oil in place is below the structural closure and updip wells penetrate microports that provide an effective seal in this stratigraphic trap. Roberto Aguilera is president of Servipetrol Ltd. in Calgary, Canada and an adjunct professor in the Chemical and Petroleum Engineering Department at the University of Calgary, where he concentrates in teaching about the theoretical and practical aspects of naturally fractured reservoirs. He is a petroleum engineering graduate from the Universidad de America at Bogota, Colombia, and holds a master's degree and a Ph.D. in petroleum engineering from the Colorado School of Mines. He was an AAPG instructor on the subject of naturally fractured reservoirs from 1984 to 1996. He has presented his course on naturally fractured reservoirs and has rendered consulting services throughout the world. He is a Distinguished Author of the Journal of Canadian Petroleum Technology (1993 and 1999), a recipient of the Outstanding Service Award from the Petroleum Society of the Canadian Institute of Mining, Metallurgy, and Petroleum Engineers (CIM) in 1994, and a Society of Petroleum Engineers Distinguished Lecturer on the subject of naturally fractured reservoirs for 2000–2001.

Description: In this study, soil magnetic measurements (susceptibility and hysteretic parameters) and soil hydrocarbon analyses were conducted on samples from three profiles (profiles I and II run across, and profile III runs parallel to the trend of the Jingbian gas field in the Ordos basin, central China) to determine the relationship between the magnetic anomalies (e.g., volume-specific magnetic susceptibility k ) and the hydrocarbon seepage environments. The results document a strong correlation between magnetic susceptibility and soil-gas hydrocarbon concentration. Furthermore, the spatial distribution of k and hydrocarbon anomalies correlate with those of the gas field. In addition, magnetic minerals in the soils with higher susceptibility are predominantly magnetite, with little or no substitution of titanium compared to that of samples with lower susceptibility (〈7 × 10−5 SI [International Unit of susceptibility]). These results provide strong evidences for the formation of highly magnetic minerals in close association with hydrocarbon seepage. Recognition of such seepage-induced magnetic anomalies can be used to facilitate the exploration for oil and gas in China and elsewhere. Qingsheng Liu received his early training in applied geophysics at Beijing Geological College. He is a professor in geophysics in China University of Geosciences. His research interests are magnetic response of hydrocarbon microseepage above oil and gas reservoir and magnetic structure of the continental crust.Lungsang Chan is an associate professor at the University of Hong Kong. He received a B.S.Sc degree (1978) in geography at the Chinese University of Hong Kong and an M.A degree (1980) and a Ph.D. (1984) in geology at the University of California, Berkeley. His major research interests concerns paleomagnetism and geophysics of engineering and environment. Qingsong Liu is currently a Ph.D. student at the University of Minnesota. His major is application of rock magnetism to both paleoclimatic and paleomagnetic studies. Haixia Li received a B.S. degree (2001) and an M.S. degree (2003) in geophysics from the China University of Geosciences (Wuhan) and is currently in the Department of Earth Sciences of Kunming University of Science and Technology. Her research interest is environmental geophysics. Fang Wang received a B.S. degree (2001) and is now a graduate student majoring in geophysics at the China University of Geosciences (Wuhan). Her major research interest is interpretation of aeromagnetic anomaly. Shuangxi Zhang received a B.S. degree (1983) and an M.S. degree (1986) in applied geophysics from the China University of Geosciences (Wuhan) and a Ph.D. (2003) in earth sciences at the University of Hong Kong. His research interests are in seismic prospecting and their applications in geophysics of engineering and petroleum. Xianghua Xia is a researcher at the Hefei Institute of Petroleum Geochemical Exploration, SINOPEC. He obtained his B.S. degree (1986) in geochemistry at the China University of Geosciences (Wuhan) and a Ph.D. (2003) in petroleum geology at Chengdu University of Technology. His research interest is oil and gas geochemical exploration. Tongjin Cheng received a B.S. degree (1978) in petroleum geology from Chengdu University of Technology. He is a professor at the Institute of Petroleum Geochemical Exploration, Heifei, SINOPEC. His specialization is in oil/gas migration and geochemical exploration.

Description: The Council Run field of north central Pennsylvania is one of the most productive natural gas fields in the central Appalachian basin. The field is enigmatic because of its position near the eastern edge of the Appalachian Plateau, where strata with reservoir potential elsewhere have low porosities and permeabilities or are poorly sealed. Council Run has four principal reservoir sandstones. The lower three occur in a distinct fourth-order type 1 stratigraphic sequence. The stacking pattern of sandstones in this sequence defines lowstand, transgressive, and highstand systems tracts. Core, well-log, and map interpretations reveal that the lowest interval consists of multiple coarsening-upward parasequences deposited in deltaic and nearshore environments of the lowstand systems tract during a forced regression. Most of these sandstones are lithic, and some are highly feldspathic. Productive sandstones display hybrid void textures that consist of reduced primary intergranular pores preserved, in part, by relatively early petroleum emplacement and secondary oversized fabric-selective pores. The generative potential of the organic matter in the potential source rocks is exhausted, but geochemical and petrographic evidences indicate that these black shales originally contained oil-prone kerogens and generated liquid hydrocarbons. Stable isotope geochemistry suggests that gases were generated by primary cracking of kerogens and/or by secondary cracking of oil between 320 and 290 Ma. Dispersive migration paths were both lateral and vertical because of compression associated with Alleghanian orogenesis. Most of the oil in the Devonian section was cracked to gas during deeper burial between 270 and 240 Ma. Christopher D. Laughrey is a senior geologic scientist with the Pennsylvania Geological Survey where he has worked since 1980. He also teaches a graduate course in sandstone petrology for the Department of Geology and Planetary Sciences at the University of Pittsburgh. Laughrey worked as a geophysical analyst for the Western Geophysical Company in Houston, Texas, before taking his present position in Pittsburgh, Pennsylvania. His special interests include isotope and organic geochemistry, sedimentary petrology, borehole geophysics, and geographic information system applications in the earth sciences.Dan A. Billman received his B.S. degree from the University of Toledo in 1986 and his M.S. degree from West Virginia University in 1989. Dan worked for Mark Resources Corporation and Eastern States Exploration Company prior to forming Billman Geologic Consultants, Inc., where he is president and principal geologist. Dan's current interests include geologic and economic evaluation of development and exploratory projects, especially in the Appalachian basin. Michael R. Canich has worked 26 years in the oil and gas industry, beginning with two years developing exploration prospects in the Gulf of Mexico. The last 24 years have been spent in the Appalachian basin exploring and developing natural gas in Silurian and Devonian aged tight gas sand reservoirs. He is currently the director of Reserve Development for Equitable Production Company in Pittsburgh, Pennsylvania.

Description: The high-pressure and high-temperature (HPHT) areas of the central North Sea constitute an important hydrocarbon province. This includes the deep, Mesozoic reservoirs in United Kingdom quadrants 22, 23, 29, and 30. This study was undertaken to better understand oil and gas compositional histories in HPHT hydrocarbon systems and to help identify new exploration opportunities. The Late Jurassic Kimmeridge Clay Formation has been the source for both oil and gas over the entire area, with additional gas charge from the humic coals of the Middle Jurassic Pentland Formation in the western graben areas. The southern Forties Montrose high, with its southward-plunging Mesozoic terraces, is host to numerous oil and gas fields with temperatures ranging from 90 to 180°C and formation pressures whose gradient to the surface exceeds 0.8 psi/ft (0.192 MPa/m). Several of these oil accumulations have undergone in-reservoir thermal cracking, resulting in a lighter, single-phase fluid, together with a pyrobitumen residue in the pore volumes. With several traps at or near their leak-off pressure, the likelihood of top seal failure and gas leakage is prevalent. Such top seal failure is intermittent and, in some instances, is associated with gas chimneys. The main causes of pressure increase in Mesozoic sediments are thought to be volume increases associated with gas generation from source rocks, clay dehydration, and thermal cracking of oil. Top seal failure because of pressure buildup by salt diapirism and the buoyancy of large hydrocarbon columns has resulted in a series of compositionally fractionated oils and gases. A new technique is presented, whereby the geochemical character of a shallow (Tertiary) oil reservoir that has undergone fractionation can help lower the risk of detecting the presence of hydrocarbon at depth in potential, deep (Mesozoic) reservoirs. Gary Isaksen coordinates geoscientists and technical programs in ExxonMobil's Upstream Geoscience companies. Isaksen holds B.Sc. and M.Sc. degrees and a Ph.D. from the University of Bergen, Norway. Since he joined Exxon in 1985, he has worked on hydrocarbon system analyses in numerous sedimentary basins worlwide as well as the application of petroleum geochemistry to development and production.

Description: Reservoir characterization, modeling, and simulation were undertaken to improve production from Womack Hill field (eastern Gulf Coast, United States). This field produces oil from Upper Jurassic Smackover carbonate shoal reservoirs. These reservoirs occur in vertically stacked, heterogeneous depositional and porosity cycles. The cycles consist of lime mudstone and wackestone at the base and ooid grainstone at the top. Porosity has been enhanced through dissolution and dolomitization. Porosity is chiefly interparticle, solution-enlarged interparticle, grain moldic, intercrystalline dolomite, and vuggy pores. Dolostone pore systems and flow units have the highest reservoir potential. Petroleum-trapping mechanisms include a fault trap (footwall uplift with closure to the south against a major west-southeast–trending normal fault) in the western area, a footwall uplift trap associated with a possible southwest-northeast–trending normal fault in the south-central area, and a salt-cored anticline with four-way dip closure in the eastern area. Potential barriers to flow are present as a result of petrophysical differences among and within the cycles, as well as the presence of normal faulting. Reservoir performance analysis and simulation indicate that the unitized western area has less than 1 MMSTB of oil remaining to be recovered, and that the eastern area has 2–3 MMSTB of oil to be recovered. A field-scale reservoir management strategy that includes the drilling of infill wells in the eastern area of the field and perforating existing wells in stratigraphically higher porosity zones in the unitized western area is recommended for sustaining production from the Womack Hill field. Ernest A. Mancini is regional director of the Eastern Gulf Region of the Petroleum Technology Council, director of the Center for Sedimentary Basin Studies, and professor in petroleum geology in the Department of Geological Sciences at the University of Alabama. His research focus is on reservoir characterization and modeling, petroleum systems, and the application of stratigraphic analysis to petroleum exploration.Tom Blasingame is an associate professor in the Department of Petroleum Engineering at Texas A&M University. He holds B.S. and M.S. degrees and a Ph.D. from Texas A&M University in petroleum engineering. He is a distinguished member of the Society of Petroleum Engineers and a member of the Society for Exploration Geophysicists and AAPG. Rosalind Archer holds a Ph.D. in petroleum engineering from Stanford University. Her research interests are in reservoir characterization, well testing, and reservoir simulation. She is currently a lecturer in the Department of Engineering Science at the University of Auckland, Auckland, New Zealand. She is also an adjunct assistant professor in the Department of Petroleum Engineering at Texas A&M University. Brian Panetta is a research associate in the Department of Geological Sciences at the University of Alabama. He received a B.S. degree from the University of South Carolina, an M.S. degree from the University of Kentucky, and an M.S. degree and a Ph.D. from the University of Alabama. His research interests are in reservoir characterization and geologic modeling. Juan Carlos Llinás obtained his B.A degree from the National University of Colombia in 1995 and his M.S. degree in 2003 from the University of Alabama, and he is currently working on his Ph.D. at the University of Alabama. He works in geologic modeling of oil fields with siliciclastic and carbonate reservoirs using well-log, core, and seismic data. Charles D. Haynes is a businessman and educator with degrees in mining and petroleum engineering. He was an independent petroleum producer before joining the faculty at the University of Alabama. He continues his professional practice through minerals-related research, consulting, and joint ownership of an independent oil-producing company. He serves on the State Board of Licensure for Engineers and Land Surveyors. Joe Benson is a professor in the Department of Geological Sciences and senior associate dean of the College of Arts and Sciences at the University of Alabama. His research interests lie in carbonate sedimentology and sedimentary petrology. He received a B.A. degree from the College of Wooster and an M.S. degree and a Ph.D. from the University of Cincinnati.

Description: The inland basins of Nigeria comprise the Anambra basin, the lower, middle, and upper Benue trough, the southeastern sector of the Chad basin, the Mid-Niger (Bida) basin, and the Sokoto basin. Organic geochemical and organic petrologic studies indicate that coal beds constitute major potential source rocks in the whole of the Benue trough (Anambra basin inclusive). The generation and production of liquid and gaseous hydrocarbons from coal beds is presently indisputable worldwide. In the Anambra basin, the coal beds in the Mamu Formation (Campanian–Maastrichtian) have total organic carbon (TOC) contents of as much as 60.8 wt.%, mean hydrogen index (HI) of 364 mg HC/g TOC, vitrinite reflectance (Ro) of 0.54–0.56%, and T max 430–433°C. Biomarker data indicate a dominance of high-molecular-weight n-alkanes, very high pristane/phytane ratios, pronounced odd-over-even predominance (OEP), a preponderance of C29 regular steranes, and relatively high contents of C28. In the middle Benue trough, the coal beds of the Turonian–Coniacian Awgu Formation have TOC contents of as much as 79.1 wt.%, Ro of 0.83–1.07%, and mean HI of 281 mg HC/g TOC, unimodal distributions of both low- and high-molecular-weight n-alkanes with no obvious OEP, a predominance of C29 steranes, and relatively high contents of C27 and C28. Coal beds from the Coniacian–lower Santonian Lamja Formation in the upper Benue trough yielded TOC contents of as much as 50.7 wt.%, with HI of 184 mg HC/g TOC, Ro of 0.70–0.73%, low- and high-molecular-weight n-alkane dominance with an unpronounced OEP, high pristane/phytane ratios, and very high contents of C29 regular steranes. On a basinal evaluation level, incorporating source rock data from the other formations in the respective sectors, plots on the modified Van Krevelen diagram alongside biomarker and maceral data indicate good to fair source rock qualities (oil and gas) in the Anambra basin and middle Benue trough and fair to poor source rock qualities (gaseous to dry) in the upper Benue trough and the Chad basin, with sporadic good to fair source rock qualities in the Lamja Formation (coals) and shales of the Cenomanian–Coniacian Yolde, Dukul, and Pindiga Formations in that part of the Benue trough. Although TOC values and liptinite contents are relatively high in the Mid-Niger (Bida) basin, T max values and biomarker data show that hydrocarbons are probably just being generated in the basin and may not yet have been expelled nor migrated in large quantities. Nuhu is currently a professor of geology at the Nasarawa State University, Keffi, Nigeria (formerly Associate Professor at the Abubakar Tafawa Balewa University, Bauchi, Nigeria). He graduated with B.Sc. and M.Sc. degrees in geology from the Ahmadu Bello University, Zaria, in 1984 and 1987, respectively, and received a Ph.D. in geology from the University of Tuebingen (Germany) in 1994. He held the Royal Society of London postdoctoral fellowship in petroleum geochemistry at the University of Aberdeen, Scotland, in 1997; the German Academic Exchange Service (doctoral and postdoctoral) fellowships in organic petrology and biostratigraphy at the University of Tuebingen in 1990–1994 and 1998; and the Alexander von Humboldt research fellowship in organic geochemistry/organic petrology at the Federal Institute for Geosciences and Natural Resources in Hanover, Germany in 2002–2003. Nuhu also held research tenures with the Exploration Departments of Chevron Nigeria Limited, Lagos (1997–1998), and the Shell Petroleum Development Company of Nigeria Limited in Port Harcourt (2000–2001). He is a member of the Nigerian government's Presidential Committee on Oil and Gas Sector Policy Reform for the National Council on Privatization.Hermann Wehner is the geological director and head of the Organic Geochemistry and Organic Petrology Section at the Federal Institute for Geosciences and Natural Resources in Hanover, Germany. Georg Scheeder, born September 8, 1964, has been working since 1991 in the Organic Geochemistry Section at the Federal Institute for Geosciences and Natural Resources in Hanover, Germany. He obtained the diploma in chemical engineering from the University of Paderborn, Germany, in 1991. He is currently working on his Ph.D. on geochemical investigations of late glacial to Holocene lake sediments in Germany. M. B. Abubakar, born October 3, 1970, is a lecturer at the Abubakar Tafawa Balewa University Bauchi, Nigeria. He obtained a B.Tech. (with honors) degree in applied geology and an M.Sc. degree in sedimentology/petroleum geology from that university in 1995 and 2001, respectively. He is currently working on his Ph.D. on a subject matter that combines organic geochemistry, micropaleontology and sedimentology, and the relationship to the hydrocarbon prospectivity of the upper Benue trough. As a part of Chevron Nigeria Limited's university linkage and community services program, he worked as a well-site geologist in April–May 2000 on Nasara-1 well at Futuk in Bauchi State (Nigeria). M. B. was a recipient of the German Academic Exchange Service scholarship to undertake analyses on some parts of his doctoral project at the University of Tuebingen in Germany (May–August 2003). He is presently the chairman of the Nigerian Mining and Geosciences Society, Bauchi/Gombe Chapter. Aliyu Jauro, born June 27, 1971, is a lecturer in the Department of Chemistry at the Abubakar Tafawa Balewa University (ATBU) Bauchi, Nigeria. He obtained B.Tech. (with honors) and M.Sc. degrees in chemistry from ATBU in 1995 and 2001, respectively. He is currently working on the hydrocarbon potential and technological properties of some Nigerian coal deposits for his Ph.D.

Description: The Cerro Toro Formation in the Torres del Paine National Park, southern Chile, contains a series of deep-water channel complexes deposited in an elongate Andean foreland basin during the Late Cretaceous. This stratigraphic interval represents an essentially continuous depositional record of migrating, leveed-channel complexes. Collectively, the channel-fill units in the study area form a belt approximately 5 km (3 mi) wide and several hundred meters thick. Within the study area, four sets of channel complexes are identified. This paper focuses on the best exposed of these channel-complex sets (channel-complex set 3). The channels are filled by bedded conglomerate and amalgamated sandstones interpreted to represent the deposits of high-concentration turbidity currents and debris flows. Large-scale cross-beds in some of the conglomerates indicate significant bed-load transport of gravel- and cobble-forming bars in the channels. Channel axis to margin facies changes between clast-supported conglomerate and either (1) thick-bedded sandstone or (2) matrix-supported conglomerate are observed. Channel-fill facies lie on erosional surfaces that cut into adjacent interchannel facies. Beds thin and onlap these surfaces toward the channel margins. Shale or siltstone drapes of the channel cuts are uncommon and laterally discontinuous. Bed continuity between channel and adjacent, interchannel facies is not observed. The interchannel strata are interpreted to represent levee successions that bound the channels. Stratigraphy in the levee units is defined to include (1) basal, sandy lobe deposits comprised of medium- to thick-bedded turbidites and (2) overbank facies consisting primarily of packages of fining- and thinning-upward, fine-grained, thin-bedded turbidites. This vertical succession is transitional. Distal levee facies include mudstones with thin-bedded, laterally continuous sandstones. Proximal levee facies include mudstones with both thin- and thick-bedded sandstones; however, the thick-bedded sandstones have lower lateral continuity. The proximal levee facies have a higher sandstone percentage than the distal levee, but also have greater depositional and postdepositional complexity, with sand-filled crevasses, erosional truncation, and slumped beds. Field observations suggest that these leveed channels formed in stages that are represented by depositional and/or erosional events. In chronological order, these are (1) an initial stage of relatively unconfined, sand-rich deposition; (2) aggradation of a mud-rich, confining levee system resulting from overbank deposition as turbidity flows bypass the area; (3) erosion as the channel becomes entrenched or as the channel migrates; and (4) filling of the channel-margin relief by onlap of channel-fill sediments. These stages appear to have repeated several times during the formation of a series of channel complexes. In these ways, the Cerro Toro Formation appears analogous to leveed-channel systems observed in late Pleistocene submarine fans and subsurface examples. Rick Beaubouef earned a Ph.D. in geology from the University of Houston in 1992. Since then, he has worked as a geologist for Exxon and later, ExxonMobil. He was previously a senior research specialist at ExxonMobil Upstream Research Co. (formerly Exxon Production Research Co.) involved in investigations of a wide range of depositional environments and basins using seismic data, well logs, core, and outcrops. However, most of his work has focused on the stratigraphy and depositional facies of deep-water reservoirs. Since 2002, he has been a stratigraphy advisor for ExxonMobil Geosciences. In this role, he is responsible for stewardship of technologies related to deep-water reservoir characterization and is involved in a wide range of exploration, development, production, research, and training activities on a global basis.

Description: Mapping in the East Gobi basin, supplemented by seismic data, reveals a structural and burial history for basins adjacent to the Zuunbayan and Tsagaan Els oil fields. The tectonic framework was combined with available well and outcrop data to model the timing and magnitude of hydrocarbon generation. Five structural episodes are recognized: (1) pre-Jurassic northeast-directed shortening that formed the tectonic fabric; (2) Middle Jurassic to Early Cretaceous rifting along northeast trends that formed the subbasins of the East Gobi basin; (3) late Early Cretaceous north-south shortening and inversion on existing normal faults; shortening caused left-lateral and reverse displacements on northeast-trending faults; (4) middle Cretaceous uplift and erosion, followed by (5) east-west shortening and right-lateral movement on northeast faults. Folds formed by inversion over Middle Jurassic–Early Cretaceous normal faults. Modeling suggests that the bituminous member of the Zuunbayan Formation should be mature over large parts of the Unegt and Zuunbayan subbasins. Oil migrated from mature source areas toward several traps, including the Zuunbayan and Tsagaan Els fields. Modeling suggests that early oil (104–110 Ma) was generated in the Zuunbayan and Tsagaan Els area because of deep burial during the Cretaceous. Although generation began in the Early Cretaceous, peak generation in the Unegt subbasin occurred between 100 and 90 Ma. Generation continued at a decreasing rate up to the present day. Kerogen maturity (and oil field production) suggests that oil is the most likely product. Scoping calculations of hydrocarbon volumes generated indicate that the Unegt basin may have generated as much as 86 billion BOE. Gary Prost received his Ph.D. in geology from the Colorado School of Mines and works for ConocoPhillips Canada on development of the Parsons Lake gas field, Northwest Territories. Over 28 years in the energy industry, he has worked for the U.S. Geological Survey, Superior Oil, Amoco, and Gulf Canada and is author of Remote Sensing for Geologists and English–Spanish Glossary of Geoscience Terms .

Description: We have developed a stochastic multifault method for analysis of the impact of stratigraphic uncertainty on cross-fault leakage at sand-sand juxtapositions. This method assumes that all sand-sand juxtapositions leak across the fault. Stratigraphic uncertainty is modeled by stochastic variation of stratigraphic stacking. Structural uncertainty is addressed through variation of the input. Our objectives were to quantitatively predict the impact of uncertainties in stratigraphic and structural input and to simulate the complex system of structural spills and juxtaposition leak points that control hydrocarbon contact levels in traps with stacked reservoir systems and many faults. Three examples demonstrate how this stochastic multifault method has helped us evaluate uncertainty and understand complex leak fill-and-spill controls. The Ling Gu prospect demonstrates that widespread cross-fault leakage on two crestal faults with throw changes that exceed seal thickness causes only a single hydrocarbon column to accumulate in multiple-stacked reservoirs. This column is controlled by a juxtaposition leak point on a third, deeper fault. We have learned from examples like Ling Gu that the relative size of throw change and seal thickness is a fundamental control on the probability of cross-fault juxtapositions. An example at prospect A demonstrates the sensitivity of hydrocarbon entrapment to small faults in a sand-prone interval with thin seals. The prospect A analysis shows that if seals are thin, faults or channel incisions below seismic resolution can leak hydrocarbons out of stacked reservoirs that are interpreted as unfaulted on seismic data. This introduced significant predrill uncertainty and risk. Guntong field demonstrates that a thin sand in a juxtaposed seal interval can introduce large uncertainty in the prediction of hydrocarbon columns. These examples and many other analyses using the method demonstrate how small changes in stratigraphic and structural input to a fault-seal analysis can introduce significant uncertainty in the predicted range of hydrocarbon volumes. Such uncertainties need to be directly and systematically accounted for in a fault-seal analysis. Bill James earned his B.S. degree in geology from Earlham College and a Ph.D. from Northwestern University in 1968. He moved on to careers at the Corps of Engineers and the U.S. Geological Survey before starting at Exxon Production Research (now ExxonMobil Upstream Research) in 1979. He worked there, specializing in statistical applications in geology, assessment, and seal analysis, until his recent retirement.Lee Fairchild has a B.A. degree in geology from the University of California, Berkeley, and an M.S. degree and a Ph.D. from the University of Washington. He joined Exxon Production Research (now ExxonMobil Upstream Research) in 1985, working on structural geology and fault-seal analysis. In 1999, he moved to Starpath Exploration as a geophysicist, prospecting in south Texas. In 2001, he began an independent consulting business. Gretchen Nakayama earned her B.S. and M.S. degrees from the State University of New York, Rochester, and her Ph.D. in geology from the University of California, Davis, in 1990. She started her career at Exxon Production Research (now ExxonMobil Upstream Research) immediately, specializing in fault-seal analysis. We are saddened by our recent loss of Gretchen to cancer. Susan Hippler has a B.A. degree in geology from Augustana College and a Ph.D. from the University of Leeds (1989). She then joined Exxon Production Research (now ExxonMobil Upstream Research) as an expert in fault-zone characterization and fault-zone migration. She transferred to ExxonMobil Exploration Co. in 1996, specializing in applications of integrated trap analysis to exploration, development, and production problems. Peter Vrolijk earned his B.S. and M.S. degrees from the Massachusetts Institute of Technology and his Ph.D. in geology from the University of California, Santa Cruz, in 1982. In 1989, he joined Exxon Production Research (now ExxonMobil Upstream Research), doing research on a wide range of topics, including most recently fault-seal analysis and fault transmissibility.

Description: The inland basins of Nigeria comprise the Anambra basin, the lower, middle, and upper Benue trough, the southeastern sector of the Chad basin, the Mid-Niger (Bida) basin, and the Sokoto basin. Organic geochemical and organic petrologic studies indicate that coal beds constitute major potential source rocks in the whole of the Benue trough (Anambra basin inclusive). The generation and production of liquid and gaseous hydrocarbons from coal beds is presently indisputable worldwide. In the Anambra basin, the coal beds in the Mamu Formation (Campanian–Maastrichtian) have total organic carbon (TOC) contents of as much as 60.8 wt.%, mean hydrogen index (HI) of 364 mg HC/g TOC, vitrinite reflectance (Ro) of 0.54–0.56%, and T max 430–433°C. Biomarker data indicate a dominance of high-molecular-weight n-alkanes, very high pristane/phytane ratios, pronounced odd-over-even predominance (OEP), a preponderance of C29 regular steranes, and relatively high contents of C28. In the middle Benue trough, the coal beds of the Turonian–Coniacian Awgu Formation have TOC contents of as much as 79.1 wt.%, Ro of 0.83–1.07%, and mean HI of 281 mg HC/g TOC, unimodal distributions of both low- and high-molecular-weight n-alkanes with no obvious OEP, a predominance of C29 steranes, and relatively high contents of C27 and C28. Coal beds from the Coniacian–lower Santonian Lamja Formation in the upper Benue trough yielded TOC contents of as much as 50.7 wt.%, with HI of 184 mg HC/g TOC, Ro of 0.70–0.73%, low- and high-molecular-weight n-alkane dominance with an unpronounced OEP, high pristane/phytane ratios, and very high contents of C29 regular steranes. On a basinal evaluation level, incorporating source rock data from the other formations in the respective sectors, plots on the modified Van Krevelen diagram alongside biomarker and maceral data indicate good to fair source rock qualities (oil and gas) in the Anambra basin and middle Benue trough and fair to poor source rock qualities (gaseous to dry) in the upper Benue trough and the Chad basin, with sporadic good to fair source rock qualities in the Lamja Formation (coals) and shales of the Cenomanian–Coniacian Yolde, Dukul, and Pindiga Formations in that part of the Benue trough. Although TOC values and liptinite contents are relatively high in the Mid-Niger (Bida) basin, T max values and biomarker data show that hydrocarbons are probably just being generated in the basin and may not yet have been expelled nor migrated in large quantities. Nuhu is currently a professor of geology at the Nasarawa State University, Keffi, Nigeria (formerly Associate Professor at the Abubakar Tafawa Balewa University, Bauchi, Nigeria). He graduated with B.Sc. and M.Sc. degrees in geology from the Ahmadu Bello University, Zaria, in 1984 and 1987, respectively, and received a Ph.D. in geology from the University of Tuebingen (Germany) in 1994. He held the Royal Society of London postdoctoral fellowship in petroleum geochemistry at the University of Aberdeen, Scotland, in 1997; the German Academic Exchange Service (doctoral and postdoctoral) fellowships in organic petrology and biostratigraphy at the University of Tuebingen in 1990–1994 and 1998; and the Alexander von Humboldt research fellowship in organic geochemistry/organic petrology at the Federal Institute for Geosciences and Natural Resources in Hanover, Germany in 2002–2003. Nuhu also held research tenures with the Exploration Departments of Chevron Nigeria Limited, Lagos (1997–1998), and the Shell Petroleum Development Company of Nigeria Limited in Port Harcourt (2000–2001). He is a member of the Nigerian government's Presidential Committee on Oil and Gas Sector Policy Reform for the National Council on Privatization.Hermann Wehner is the geological director and head of the Organic Geochemistry and Organic Petrology Section at the Federal Institute for Geosciences and Natural Resources in Hanover, Germany. Georg Scheeder, born September 8, 1964, has been working since 1991 in the Organic Geochemistry Section at the Federal Institute for Geosciences and Natural Resources in Hanover, Germany. He obtained the diploma in chemical engineering from the University of Paderborn, Germany, in 1991. He is currently working on his Ph.D. on geochemical investigations of late glacial to Holocene lake sediments in Germany. M. B. Abubakar, born October 3, 1970, is a lecturer at the Abubakar Tafawa Balewa University Bauchi, Nigeria. He obtained a B.Tech. (with honors) degree in applied geology and an M.Sc. degree in sedimentology/petroleum geology from that university in 1995 and 2001, respectively. He is currently working on his Ph.D. on a subject matter that combines organic geochemistry, micropaleontology and sedimentology, and the relationship to the hydrocarbon prospectivity of the upper Benue trough. As a part of Chevron Nigeria Limited's university linkage and community services program, he worked as a well-site geologist in April–May 2000 on Nasara-1 well at Futuk in Bauchi State (Nigeria). M. B. was a recipient of the German Academic Exchange Service scholarship to undertake analyses on some parts of his doctoral project at the University of Tuebingen in Germany (May–August 2003). He is presently the chairman of the Nigerian Mining and Geosciences Society, Bauchi/Gombe Chapter. Aliyu Jauro, born June 27, 1971, is a lecturer in the Department of Chemistry at the Abubakar Tafawa Balewa University (ATBU) Bauchi, Nigeria. He obtained B.Tech. (with honors) and M.Sc. degrees in chemistry from ATBU in 1995 and 2001, respectively. He is currently working on the hydrocarbon potential and technological properties of some Nigerian coal deposits for his Ph.D.

Description: Modern three-dimensional seismic imaging enables a basic geometric description and kinematic interpretation of part of the Fish Creek Slide, a massive (∼4000 km2; 1500 mi2) slope failure beneath Alaska's North Slope. The Fish Creek Slide is divided into a dominantly extensional organized slide zone in the west and a mostly contractional disorganized slide zone in the east. In the organized slide zone, a series of six organized slide blocks detached from the lower slope along steep escarpments during an inferred Albian earthquake focused at depth on a preexisting southeast-striking fault. Blocks were transported eastward into the basin as failure progressed catastrophically yet systematically by northwestward, en echelon, upslope, footwall collapse. During slide evolution, the primary flat detachment switched from the highly radioactive zone down stratigraphic section to the Lower Cretaceous unconformity. Although the seismic interpretation is hampered by a variety of slide-induced signal problems, several significant, previously unrecognized elements of the Fish Creek Slide are described: shear zones related to displacement variations in the slide, duplex structures in the slide blocks, postslide erosional features, and axial structural lows in slide blocks. Tom Homza is an exploration geologist for EnCana Oil & Gas (U.S.A.) Inc. He is currently working in EnCana's Alaska Office, which he helped launch and he presently manages. He holds an M.S. degree and a Ph.D. in geology from the University of Alaska, Fairbanks and a B.S. degree in geology from the University of Vermont. Tom spent seven years at BP, where he worked in both exploration and development geology in several basins.

Description: Beaufortian strata (Jurassic–Lower Cretaceous) in the National Petroleum Reserve in Alaska (NPRA) are a focus of exploration since the 1994 discovery of the nearby Alpine oil field (〉400 MMBO). These strata include the Kingak Shale, a succession of depositional sequences influenced by rift opening of the Arctic Ocean Basin. Interpretation of sequence stratigraphy and depositional facies from a regional two-dimensional seismic grid and well data allows the definition of four sequence sets that each displays unique stratal geometries and thickness trends across NPRA. A Lower to Middle Jurassic sequence set includes numerous transgressive-regressive sequences that collectively built a clastic shelf in north-central NPRA. Along the south-facing, lobate shelf margin, condensed shales in transgressive systems tracts downlap and coalesce into a basinal condensed section that is likely an important hydrocarbon source rock. An Oxfordian–Kimmeridgian sequence set, deposited during pulses of uplift on the Barrow arch, includes multiple transgressive-regressive sequences that locally contain well-winnowed, shoreface sandstones at the base of transgressive systems tracts. These shoreface sandstones and overlying shales, deposited during maximum flooding, form stratigraphic traps that are the main objective of exploration in the Alpine play in NPRA. A Valanginian sequence set includes at least two transgressive-regressive sequences that display relatively distal characteristics, suggesting high relative sea level. An important exception is the presence of a basal transgressive systems tract that locally contains shoreface sandstones of reservoir quality. A Hauterivian sequence set includes two transgressive-regressive sequences that constitute a shelf-margin wedge developed as the result of tectonic uplift along the Barrow arch during rift opening of the Arctic Ocean Basin. This sequence set displays stratal geometries suggesting incision and synsedimentary collapse of the shelf margin. Houseknecht joined the U.S. Geological Survey in 1992, serving as energy program manager until 1998. He has worked on Alaska North Slope basin analysis and petroleum resource assessment since 1995. Previously, Houseknecht was a professor of geology at the University of Missouri (1978–1992) and a consultant to the oil industry. He holds geology degrees from Penn State University (B.S. degree and Ph.D.) and Southern Illinois University (M.S. degree).Bird specializes in the petroleum geology of northern Alaska, where his experience spans more than 40 years. Currently, he is the leader of the U.S. Geological Survey Alaska Petroleum Studies Project. With interests primarily in stratigraphy and sedimentology, he has been extensively involved in petroleum resource assessments. He holds geology degrees from Oregon State University (B.S. degree) and the University of Wisconsin (M.S. degree and Ph.D.).

Description: The Gabon continental slope is selected as a case study for slope-stability analysis because of evidence of previous slide activities. Different types of data were collected from the continental slope in the Gulf of Guinea off west Africa during Guiness and ZaiAngo surveys. The offshore investigation was carried out using swath bathymetry and associated imagery, deep-towed high-resolution subbottom profiles, side-scan sonar images, observation from remotely operated vehicle Victor, and Kullenberg cores. These data reveal different examples of seafloor instabilities commonly related to fluid-escape features. These slides occur on the continental slope at low declivities, showing that slope gradient has a secondary role on the marine slope instability with respect to external triggering mechanisms such as fluid flow, earthquake, shallow gas, and gas hydrates. One case of mass slide with small downslope displacement was studied on the Gabon slope. In this work, a pseudo–three-dimensional slope-stability analysis (Sultan et al., 2001) was undertaken. Three scenarios of instability were tested to identify the possible trigger mechanism of the observed slide instability: (1) under static gravity loading, (2) under earthquakes, and (3) under upward fluid flow. Simulation results show that static stability of the area is satisfactory. However, the stability is very sensitive to fluid escape. These results agree with sonar images showing seepage features aligned along the upslope limit of the observed slide. Nabil Sultan received his Ph.D. in geotechnics from the Ecole Nationale des Ponts et Chaussées, Paris, France. He joined Institut Français de Recherche pour l'Exploitation de la Mer (IFREMER) in 2000. His main interests are laboratory and field geotechnical tests, mathematical and constitutive models in geomechanics, and slope stability and flow in porous media.Pierre Cochonat received his Ph.D. in applied geology from the Université Scientifique et Médicale de Grenoble, France. He has 26 years experience in engineering geology and sedimentology. His main field of scientific interest has been the study of sedimentary processes on slope and deep-sea sediments. He is now deputy director of Ocean Research and manager of the Continental Margin Programme at IFREMER. Florence Cayocca graduated as a civil engineer from Ecole Nationale des Ponts et Chaussées, Paris, France. After a master's degree in ocean engineering at the University of California, Santa Barbara, she completed her Ph.D. in morphodynamic modeling at IFREMER. Since then, she has worked there on sediment-transport numerical modeling on the slope and in coastal seas. Jean-François Bourillet graduated in 1982 from the Ecole Nationale Supérieure de Géologie de Nancy, France. He joined IFREMER in 1982 for submarine mining exploration. His main interests are coring operations, bathymetry processing, slope stability, and sedimentology of the Gulf of Biscay (western Europe). Jean-Louis Colliat received his Ph.D. in geotechnics from the University of Grenoble, France, in 1986. He joined Geodia in 1986, then Elf in 1991, becoming Total in 2000. His main interests are offshore geotechnical engineering, from soil investigation, design studies, and offshore installation works.

Description: The U.S. Navy nuclear research submarine NR-1 was used to investigate the Storegga Slide (Norwegian Sea) shelf break, headwall, and upper debris-flow fields to a maximum water depth of 630 m (2070 ft). About 275 km (170 mi) of seafloor was traversed in 1 week, collecting 150-kHz side-scan sonar, current speed and direction, bathymetry, optic imagery, and visual observations. Side-scan imagery was used to identify four provinces, some corresponding to distinct optic-scale characteristics. We found the Storegga outer shelf streaked and locally incised by iceberg plow marks or otherwise “lineated” in the side-scan imagery. We attribute the “streaking” to the strong Norwegian-Atlantic Current and perhaps the Norwegian Coastal Current. Despite our short current-sampling “snapshot,” we found good agreement between measured current directions and current-generated seafloor features. Along the headwall, just seaward of the iceberg plow marks, are deep-water, coral ( Lophelia pertusa ) reefs. Recent instability (post-8.15 ka) along part of the headwall region is indicated by cobble/boulder fields devoid of sessile biota (such as sponges). No obvious fluid expulsion or extensional features were discovered in the small portion of the Storegga Slide that was investigated. Brian Parsons has a B.S. degree in geology (1994) and a Ph.D. in oceanography (1999) from Old Dominion University. He joined Woodward-Clyde in 1998 and worked on subsea pipeline routes in the Black Sea and the Philippines. He received a National Research Council Fellowship (2000–2003) and studied continental slope stability on the Norwegian margin. His main interests are using sonar and seafloor data to assess sediment dynamics for subsea engineering projects.A marine geophysicist working at the Naval Research Laboratory on subjects ranging from plate tectonics to methane hydrates and sediment dynamics, Peter Vogt obtained a B.S. degree from the California Institute of Technology in 1961, and a Ph.D. in oceanography at the University of Wisconsin. Vogt is a Fellow of the Geological Society of America. In 2000, he received an honorary doctorate from the University of Bergen and was elected to the Norwegian Academy of Science and Letters. In 2003, he was recognized as a Distinguished Alumnus by the University of Wisconsin. Vogt has authored or coauthored over 150 peer-reviewed papers, accumulating over 4000 citations. Haflidi Haflidason is a professor of marine geology at the University of Bergen, Norway. He received his B.S. degree from the University of Iceland in 1978, his M.Phil. degree from University of Edinburgh 1984, and his Dr.Scient. from University of Bergen in 1994. His research interests are in Quaternary stratigraphy, continental slope stability, and paleoceanography vs. marine sedimentary processes. Jung finished college at Seoul National University and studied marine geophysics at Columbia University. He received his Ph.D. from Texas A&M University and was awarded National Research Council Research Associateship at the Naval Research Laboratory. He has been working there since 1987. Jung's research area involves inversion/numerical modeling techniques related to geopotential field anomalies and recently to gas-hydrate stability under the ocean floors.

Description: In this study, soil magnetic measurements (susceptibility and hysteretic parameters) and soil hydrocarbon analyses were conducted on samples from three profiles (profiles I and II run across, and profile III runs parallel to the trend of the Jingbian gas field in the Ordos basin, central China) to determine the relationship between the magnetic anomalies (e.g., volume-specific magnetic susceptibility k ) and the hydrocarbon seepage environments. The results document a strong correlation between magnetic susceptibility and soil-gas hydrocarbon concentration. Furthermore, the spatial distribution of k and hydrocarbon anomalies correlate with those of the gas field. In addition, magnetic minerals in the soils with higher susceptibility are predominantly magnetite, with little or no substitution of titanium compared to that of samples with lower susceptibility (〈7 × 10−5 SI [International Unit of susceptibility]). These results provide strong evidences for the formation of highly magnetic minerals in close association with hydrocarbon seepage. Recognition of such seepage-induced magnetic anomalies can be used to facilitate the exploration for oil and gas in China and elsewhere. Qingsheng Liu received his early training in applied geophysics at Beijing Geological College. He is a professor in geophysics in China University of Geosciences. His research interests are magnetic response of hydrocarbon microseepage above oil and gas reservoir and magnetic structure of the continental crust.Lungsang Chan is an associate professor at the University of Hong Kong. He received a B.S.Sc degree (1978) in geography at the Chinese University of Hong Kong and an M.A degree (1980) and a Ph.D. (1984) in geology at the University of California, Berkeley. His major research interests concerns paleomagnetism and geophysics of engineering and environment. Qingsong Liu is currently a Ph.D. student at the University of Minnesota. His major is application of rock magnetism to both paleoclimatic and paleomagnetic studies. Haixia Li received a B.S. degree (2001) and an M.S. degree (2003) in geophysics from the China University of Geosciences (Wuhan) and is currently in the Department of Earth Sciences of Kunming University of Science and Technology. Her research interest is environmental geophysics. Fang Wang received a B.S. degree (2001) and is now a graduate student majoring in geophysics at the China University of Geosciences (Wuhan). Her major research interest is interpretation of aeromagnetic anomaly. Shuangxi Zhang received a B.S. degree (1983) and an M.S. degree (1986) in applied geophysics from the China University of Geosciences (Wuhan) and a Ph.D. (2003) in earth sciences at the University of Hong Kong. His research interests are in seismic prospecting and their applications in geophysics of engineering and petroleum. Xianghua Xia is a researcher at the Hefei Institute of Petroleum Geochemical Exploration, SINOPEC. He obtained his B.S. degree (1986) in geochemistry at the China University of Geosciences (Wuhan) and a Ph.D. (2003) in petroleum geology at Chengdu University of Technology. His research interest is oil and gas geochemical exploration. Tongjin Cheng received a B.S. degree (1978) in petroleum geology from Chengdu University of Technology. He is a professor at the Institute of Petroleum Geochemical Exploration, Heifei, SINOPEC. His specialization is in oil/gas migration and geochemical exploration.

Description: Modern three-dimensional seismic imaging enables a basic geometric description and kinematic interpretation of part of the Fish Creek Slide, a massive (∼4000 km2; 1500 mi2) slope failure beneath Alaska's North Slope. The Fish Creek Slide is divided into a dominantly extensional organized slide zone in the west and a mostly contractional disorganized slide zone in the east. In the organized slide zone, a series of six organized slide blocks detached from the lower slope along steep escarpments during an inferred Albian earthquake focused at depth on a preexisting southeast-striking fault. Blocks were transported eastward into the basin as failure progressed catastrophically yet systematically by northwestward, en echelon, upslope, footwall collapse. During slide evolution, the primary flat detachment switched from the highly radioactive zone down stratigraphic section to the Lower Cretaceous unconformity. Although the seismic interpretation is hampered by a variety of slide-induced signal problems, several significant, previously unrecognized elements of the Fish Creek Slide are described: shear zones related to displacement variations in the slide, duplex structures in the slide blocks, postslide erosional features, and axial structural lows in slide blocks. Tom Homza is an exploration geologist for EnCana Oil & Gas (U.S.A.) Inc. He is currently working in EnCana's Alaska Office, which he helped launch and he presently manages. He holds an M.S. degree and a Ph.D. in geology from the University of Alaska, Fairbanks and a B.S. degree in geology from the University of Vermont. Tom spent seven years at BP, where he worked in both exploration and development geology in several basins.

Description: The central Scotian Slope demonstrates a complex seafloor morphology superimposed on a regional gradient of 2–4° across the margin. The west-central Scotian Slope is characterized by a relatively smooth seafloor, but with numerous 10–80-m (33–260-ft)-high escarpments representing slide failure scars. In the east, the seafloor is highly dissected by canyons. Throughout the region are scars and deposits of sediment mass failures, including retrogressive headwalls, rotational slumps, slides, creep, debris-flow deposits, and turbidites. The complexity of failure styles and triggering mechanisms identified underscores the need for comprehensive site assessments for situating seabed facilities. Critical factors that need to be taken into account include local terrain analysis and shallow subbottom stratigraphy. Slope-stability analysis has shown the surface sediment to be statically stable, except on steep escarpments and canyon walls. There is evidence, however, of sediment failures that approximately correlate to glacial advances (25–12, ∼75, and ∼130 ka), providing some clue as to potential triggering mechanisms. Sparse, passive-margin, tectonic earthquakes, however, are the likely cause for large-scale, regionally correlated failures and failure escarpments. David Mosher is a marine research geophysicist with the Geological Survey of Canada. He graduated with a Ph.D. from Dalhousie University in 1993. His research interests include marine geohazard investigations, with particular emphasis on neotectonics and slope stability. He has worked on Canada's east and west coasts, the Arctic, and the equatorial Atlantic and Pacific. He was recently co-chief scientist on Ocean Drilling Program (ODP) Leg 207.David Piper is a marine research geologist with the Geological Survey of Canada. He completed his Ph.D. in sedimentary geology at Cambridge University in 1969. He has a long-standing interest in continental margin stratigraphy and sedimentation and is presently assigned to work on geohazards on the eastern Canadian margin. He has been senior scientist on more than 30 research cruises, including ODP Leg 155. Calvin Campbell is a marine geoscientist with the Geological Survey of Canada, specializing in geohazard evaluation, digital geological interpretation, and geographic information systems, with a particular emphasis on deep-water environments. He graduated in 1999 with a B.Sc. degree in geology and environmental studies from St. Mary's University and conducted an honors thesis under the guidance of David Piper on Holocene storm signature in marine sediment cores. Kimberley A. Jenner was employed as a sedimentologist with Gulf Canada Resources Incorporated from 1982 to 1986 before graduating with an M.Sc. degree from Dalhousie University in marine sedimentology in 1989. Kimberley has worked as a sedimentologist with Natural Resources Canada since 1990. Her research interests include arctic deltas, arctic gas hydrate host strata, and shallow mass-transport deposits in deep-water canyons.

Description: Burrow-associated, selective dolomitization in the Yeoman Formation limestone (Ordovician, Williston basin) is characterized by distinct textural heterogeneity. Physical parameters such as permeability, porosity, tortuosity, and dispersivity are therefore difficult to assess. This study compares the relative dispersivities of three geologic media: homogeneous sandstone, fractured limestone, and burrowed dolomitic limestone. Results show that the flow paths present in burrow-associated dolomite are tortuous, and that the interaction between the flow paths and the matrix is extensive. Such rocks act as dual-permeability systems in the subsurface. Hydrocarbon production from such deposits will be strongly influenced by burrow-related heterogeneity, and its influence should be carefully considered before secondary recovery schemes are implemented. Murray Gingras received his diploma in mechanical engineering technology from the Northern Alberta Institute of Technology in 1987, his B.Sc. degree from the University of Alberta in 1995, and his Ph.D. from the University of Alberta in 1999. Gingras has worked professionally in the hydrocarbon industry, at the Northern Alberta Institute of Technology, and as an assistant professor at the University of New Brunswick. His research focuses on applying sedimentology and ichnology to sedimentary rock successions, as a paleoecological tool, a reservoir development tool, and in process-driven sedimentology.Carl Mendoza received a B.A.Sc. degree in geological engineering from the University of British Columbia in 1984. He worked for Shell Canada Resources for more than two years, before obtaining his M.Sc. degree and his Ph.D. in hydrogeology from the University of Waterloo. He has been at the University of Alberta since 1992 and is currently an associate professor. His research focuses on reactive gas and vapor transport in the unsaturated zone, ground-water/surface-water interactions at both natural and oil-sands impacted sites, and flow and transport in heterogeneous porous media. S. George Pemberton is a professor in the Department of Earth & Atmospheric Sciences at the University of Alberta. He is a Fellow of the Royal Society of Canada and holds a Canada Research Chair in Petroleum Geology (Natural Sciences and Engineering Research Council). George's field of research and expertise are in the field of ichnology, the investigation of animal-sediment interactions in both recent and ancient environments. Current research activities include the application of trace-fossil studies in sequence stratigraphy and the exploration and exploitation of hydrocarbons. Recent research activities involve emphasis on the Cardium and Viking formations, the Athabasca and the Cold Lake oil sands of Alberta, as well as the offshore Hibernia, Ben Nevis, Terra Nova, and Venture fields.

Description: The Banda Arc in eastern Indonesia and newly independent Timor-Leste (East Timor) is the zone of collision between the northern margin of the Australian continent and an oceanic island arc system bordering the Eurasian plate. Structurally, the Banda forearc is a fold and thrust belt, consisting of the imbricated outer edge of the Australian continent, overlain locally by fragments of the precollisional oceanic forearc. The Banda forearc is an established petroleum province in the island of Seram, but the remainder of the forearc has so far yielded no further exploration success despite close geological similarity to Seram. A major disincentive to exploration in the Banda forearc has been a common perception of structural complexity. This complexity may, however, have been overstated, and this paper presents a simple structural model for the evolution of the Banda forearc. Key to this model is the recognition of basement-involved inversion structures in the deeper parts of the collision complex. The inverted graben basins are filled with Permian–Jurassic continental margin sequences, including high-quality source rocks of Late Triassic–Early Jurassic age, and contemporaneous potential reservoir sequences, sealed by Middle–Late Jurassic shales. These Jurassic shales also act as an important decollement horizon, separating shallow-level structural complexity from a simpler structural style beneath, characterized by large inversion anticlines. The Oseil field in Seram may be located in such an inversion anticline, and comparable prospective structures are identified elsewhere in the Banda forearc, particularly in Timor and the Tanimbar islands. Tim Charlton received a B.Sc. degree in geology from University College London in 1982 and a Ph.D. from Royal Holloway College, London University, in 1987 for a study of southern West Timor and the offshore Timor Trough. From 1987 to 1989, he carried out postdoctoral studies in eastern Indonesia, including fieldwork in the Tanimbar and Kei islands (Banda Arc) and the Sorong fault zone. Since 1990, he has combined academic research with oil industry consultancy studies, focusing on the eastern Indonesia region. He is an Honorary Research Fellow at University College London.

Description: In offshore East Kalimantan, Indonesia, three-dimensional seismic reflectors can be traced downslope from a lowstand delta to a basin-floor fan, giving insight into depositional processes controlling the distribution of sands that serve as hydrocarbon reservoirs in many ancient deep-water settings. The studied interval includes the last three Pleistocene cycles (10–330 ka; each ∼110 k.y. in duration). Cycles on the shelf are dominated by progradational packages deposited during highstands and falling eustatic sea level. Progradational packages are separated by parallel reflectors and carbonate buildups of the transgressive systems tracts. During the last two lowstands of sea level (∼18 and ∼130 ka), coarse clastics were not deposited in deep-water environments because growth faults and regional subsidence prevented lowstand deltas from reaching the slope. During the lowstand of sea level that ended at about 240 ka, a delta prograded over the previous shelf edge, and sand-rich sediments spilled onto the slope. Strata on the slope and basin floor show how a deep-water depositional system evolved during a single cycle of eustatic sea level. A canyon on the slope connects the 240-ka lowstand delta to a coeval basin-floor fan. The canyon has a sinuous, bipartite fill that consists of a lower, amalgamated channel complex and an upper channel-levee complex. The basin-floor fan formed at the toe of the slope also has two parts. The stratigraphically lower part of the basin-floor fan has broad lobes with relatively continuous reflectors. The stratigraphically higher part has a sinuous channel-levee complex that prograded over the lower fan and fed sheetlike lobes on the outermost fan. The amalgamated channel fills on the slope and sheetlike lobes on the basin-floor fan have moderate- to high-amplitude reflectors and are inferred to represent sand-rich, early lowstand deposits. The channel-levee complexes on the slope and basin floor are dominated by low-amplitude reflectors and are inferred to be mud-rich strata deposited during the late lowstand. Unlike classic sequence-stratigraphic models, these lowstand strata do not onlap the slope; instead, deep-water clastics extend from the last clinoforms of lowstand deltas. In this system, lowstand deltas determined when and where sand-rich sediments entered preexisting canyons on the slope to feed basin-floor fans. Art Saller currently works as a sedimentologist and stratigrapher for Unocal in Sugar Land, Texas. He received geology degrees from the University of Kansas (B.S., 1974–1978), Stanford University (M.S., 1980), and Louisiana State University (Ph.D., 1984). From 1984 to 1986, he worked for Cities Service Oil and Gas in Tulsa, Oklahoma, and joined Unocal in 1986.Jesse Noah has been with Unocal for 22 years and is currently Unocal's chief geoscientist for the Deep-Water Gulf of Mexico. Initially, he worked on the United States mid-continent and Gulf of Mexico shelf. He has worked on deep-water exploration and development projects in the Gulf of Mexico and Indonesia since 1996. Jesse received his B.S. degree in exploration geophysics from the University of Oklahoma. Alif Ruzuar graduated from the Bandung Institute of Technology, Indonesia, in 1998 with a B.S. degree in geology. He earned an M.Sc. degree in petroleum geoscience from the University of Brunei Darussalam (1999). Alif joined Unocal Indonesia in 2000 as a deep-water exploration geophysicist and is currently working as a development geophysicist for fields on the East Kalimantan shelf. Rhys Schneider received his B.S. degree in geological engineering from the Colorado School of Mines in 1978. He joined Unocal in 1980 and has worked as an exploration and development geologist in the Anadarko basin, Permian basin, and many other basins throughout the world. He currently specializes in detailed, seismic-defined, reservoir characterization for deep-water systems of the Kutei Basin, Indonesia.

Description: The Qaidam basin is a continental petroliferous basin located in northwest China. Its northern sector is an important hydrocarbon province, where one of the earliest oil discoveries in China was made. Although Mesozoic source rocks are understood to be important parts of Qaidam petroleum systems, the identification and distribution of Mesozoic source rocks in the subsurface are poorly understood. Middle Jurassic coal measures and associated shales have long been considered to be the primary Mesozoic source rocks for the northeastern Qaidam basin without any support from subsurface geochemical and geological data. However, new data have been gathered from earlier Mesozoic sediments that were penetrated by the Lengke-1 well, a deep scientific well with a total depth of 5200 m (17,060 ft). The well was drilled on the Lenghu structural belt in 1997 and documented other effective source rocks. Geochemical analyses indicate that Lower Jurassic mudstones are good to excellent source rocks for the commercial oil wells in the Lenghu area. The upper Middle Jurassic shales are very good source rocks for the commercial oil wells in the Yuka area. Two source rock intervals in the northeastern Qaidam basin allow for two petroleum systems to be distinguished, the Lower Jurassic–Lower Jurassic/Tertiary and Middle Jurassic–Upper Jurassic. The Lower Jurassic–Lower Jurassic/Tertiary petroleum system, with a geographical extent of 15,000 km2 (5800 mi2) and a cumulative amount of source rocks between 200 and 700 m (650 and 2300 ft), represents a favorable target for future exploration. The Middle Jurassic–Upper Jurassic petroleum system, however, may have a lower exploration potential because of a smaller area (1500 km2 [580 mi2]) and a thinner cumulative amount of source rocks (100–200 m [330–650 ft]). Yongtai Yang is a Ph.D. candidate at the University of Toronto, studying sequence stratigraphy and basin analysis. He received an M.S. degree in geology from the China Research Institute of Petroleum Exploration & Development (RIPED) in 1996. He worked as a petroleum geologist at RIPED from July 1996 to July 2003.Baomin Zhang received his M.S. degree in geology from the Beijing Normal University in 1989. He currently is a senior geologist focusing on sedimentology and petroleum geochemistry at RIPED. Before joining RIPED in 1994, he worked as an associate professor at the Beijing Normal University. Changyi Zhao received his Ph.D. in geology from the Chinese University of Mining and Technology in 1991. He currently is a senior geologist focusing on petroleum geochemistry and petroleum geology at RIPED. Tianguang Xu received his M.S. degree in geology from Kansas State University in 2001. He is currently a basin researcher with IHS Energy, focusing on Chinese basins.

Description: The Meren E-01 (Agbada Formation, middle Miocene) reservoir offshore Nigeria consists of a lower progradational shoreface succession terminated by a minor sequence boundary, overlain by a progradational and retrogradational shoreface succession. Deposition occurred in a wave-dominated delta front, as indicated by the presence in core of hummocky cross-beds, slumped units, and turbidites. Eight flooding surfaces were correlated, and isopach maps, sandstone-quality trend maps, and mudstone-quality trend maps were constructed for each parasequence. This work revealed a complex reservoir architecture characterized by shoreface clinoforms and a history of progradation and retrogradation cycles. Three different three-dimensional geological characterizations of the E-01 reservoir were built: a geostatistical model that used only well data; a more geologically complex facies-based model that used the sandstone-quality trend maps in addition to well data; and the most geologically complex sequence-stratigraphic model that used mudstone-quality trend maps in addition to the above data. The three models were analyzed in terms of sandstone continuity and connectivity to hypothetical injector and producer wells. Only the sequence-stratigraphic model predicted significant vertical compartmentalization through tortuosity generated by flooding-surface mudstones. Waterflood fluid-flow simulation of a downdip sector of the geologic models predicts similar recovery for the three models, but a significantly different distribution of unswept oil. Only the sequence-stratigraphic model identified parasequences with abundant unswept oil that are large enough to be economic infill prospects. History-matched, full-field fluid-flow simulations verify both the reservoir compartments predicted by the sequence-stratigraphic model and infill targets. Dave Larue has worked for ChevronTexaco Corporation for the past six years studying sequence stratigraphy and geologic modeling. Formerly, he worked at Exxon Production Research. Prior to joining the oil industry, he was a professor at the University of Puerto Rico and an original member of “los Profesores,” a rock-and-roll band that toured the western part of the island for several years. He received his Ph.D. from Northwestern University and was the last Ph.D. student of Larry Sloss, the father of sequence stratigraphy. He is an AAPG Visiting Petroleum Geologist and member of the AAPG Distinguished Lecturer Selection Committee.Henry Legarre received his M.S. degree from San Diego State University. He started working at ChevronTexaco in 1991, after spending some time at Scripps Institution of Oceanography, and Woods Hole Oceanographic Institute. He has worked for ChevronTexaco as an Earth scientist in California (Bakersfield, La Habra, and San Ramon), Luanda, Angola, and is currently in Lagos, Nigeria. His areas of expertise are production geology, geochemistry, carbonate and clastic stratigraphy, reservoir characterization, and geologic modeling. He has also been the chairman of the AAPG Student Chapter Committee and serves on the AAPG Grants-in-Aid Committee.

Description: Seismic data from the Angolan margin and laboratory experiments on brittle-ductile models are used to study thin-skinned deformation above the salt at margin scale, which is characterized by extension upslope and contraction downslope. The initial geometry of the salt basin was wedging out, both landward and seaward, and the salt was entirely covered by sediments at the onset of gravity-driven deformation. Downslope contraction is accommodated by upslope extension. The upslope extensional domain is subdivided into three subdomains with (1) sealed tilted blocks, (2) growth fault and rollover systems, and (3) extensional diapirs. We interpret this particular arrangement of extensional structures as directly resulting from variations in mechanical coupling between brittle (sediments) and ductile (salt) layers. The downslope contractional domain is subdivided into three subdomains with (1) diapirs squeezed at late stage, (2) polyharmonic folds and thrust faults developed at early stage, and (3) folds and thrusts developed at late stage. This structural zoning results from the initiation of contraction at a distance from the salt toe and further migration of contraction immediately downslope and upslope. Xavier Fort earned an M.S. degree in geology (1998) and a Ph.D. in geology (2002) from the University of Rennes 1, France. His thesis topic concerned salt tectonic processes of the Angolan margin. He is now working as a consultant for Norsk Hydro and extended his interest in salt tectonics to Canada, Gulf of Mexico, and Brazil.Jean-Pierre Brun is a professor of tectonics at University Rennes 1, France. His research mainly concerns structural geology, basin development, and lithosphere deformation, with application to the European Variscides, Aegean, Atlantic passive margins, and the North Sea. Through analog modeling, he is especially interested in the mechanics of brittle-ductile systems, with particular application to salt tectonics. Francois Chauvel received his postgraduate degree in geology from the University of Rennes in 2001. He then went on to specialize in petroleum geoscience and graduated in 2003 with an M.Sc. degree from the French Petroleum Institute (IFP) in Paris. In 2003, Francois joined ExxonMobil, and he currently works as a production geologist on the Beryl field in Aberdeen, Scotland.

Description: Chip Feazel is principal carbonate stratigrapher for ConocoPhillips, with worldwide responsibility for interpreting carbonate depositional and diagenetic histories to predict reservoir properties. Following undergraduate studies at Ohio Wesleyan University, he received his M.A. degree and his Ph.D. in geology from Johns Hopkins University. In 29 years with Phillips, subsequently ConocoPhillips, he has enjoyed a variety of technical and managerial assignments in the United States and overseas in field development and technology teams.Alan Byrnes has been a research geologist at the Kansas Geological Survey since 1997, where he works on lithologic controls on rock petrophysical properties, CO2-enhanced oil recovery, reservoir characterization, and modeling. Alan received his B.S. degree in geology from the University of Illinois at Chicago and his M.S. degree in geophysical sciences from the University of Chicago. He has been a research geologist at the Institute of Gas Technology, Marathon Oil Company Research Center, Core Laboratories, and Tetra Tech, and for 13 years, he owned and operated GeoCore, a special core analysis laboratory in Colorado. With more 30 years in the oil and gas industry, Jim Honefenger has worked in virtually every segment, starting in 1972 with Elliott Company, a turbomachinery manufacturer. He held senior management positions for Scientific Software Intercomp, Intera, Energy Systems, GeoQuest Schlumberger, Western Atlas, Landmark Graphics, GeoNet Services, and Veritas Exploration Services, developing the market for geophysical, geological, petrophysical, reservoir engineering, and pipeline simulation products. More recently, he sold the intellectual assets of (RC)2 and founded his own company, Consulting Assets, representing oil and gas industry-consulting firms located throughout the world. Honefenger is an active Society of Petroleum Engineers (SPE) member and has held various positions in both the international and local groups. A cofounder of the Houston Energy Council (a professional organization comprising board members from Houston Geological Society, Geophysical Society …

Description: Shogren is the Stroock Distinguished Professor of Natural Resource Conservation and Management at the University of Wyoming. In 1997, he served as the senior economist for environmental policy at the President's Council of Economic Advisers during the runup to Kyoto. In the 1992 United Nations Framework Convention on Climate Change (UNFCCC), most countries agreed to voluntarily reduce their greenhouse gas (GHG) emissions by the turn of the 20th century (UNFCCC, 1999a). By the mid-1990s, policy makers and scientists realized that the majority of the voluntary pledges were not being met. The international community responded by increasing the pressure to formulate country-specific binding commitments to reduce emissions. The end result was the Kyoto Protocol (UNFCCC, 1999b). The protocol set targets and timetables for emission reductions; an Annex I Parties (industrialized and transition economies) is to reduce net GHG emissions by about 5% below 1990 levels by 2008–2012. Article 25 of the protocol says the agreement will enter into force 90 days after it has been ratified (or approved, accepted, or acceded to) by at least 55 parties to the convention, including Annex I Parties, accounting for 55% of the group's 1990 carbon dioxide emissions. As of May 2004, the Kyoto Protocol had not entered into force. The delay is caused in part by the lack of commitment by the United States, Australia, and Russia, and with the expected increase in GHG emissions growth driven by increasing economic growth in developing nations like China and India, the emission reductions needed to comply with Kyoto will be substantial. The Kyoto Protocol might go into force, and people still want to know for what benefit, at what cost, and who wins and who loses? Herein, we briefly review the past, present, and future of the Kyoto Protocol from an economist's benefit-cost perspective. To an …

Description: Elevated gamma-ray emission from discrete beds in sedimentary deposits may conventionally be interpreted as representing flooding surfaces or transgressive beds. Potassium (K), uranium (U), or (less commonly) thorium (Th) concentrations in outcrop or borehole successions cause such elevated gamma-ray emission and may be linked to the presence of specific mineral hosts. Furthermore, specific Th/K and Th/U ratios occur at correlated stratigraphic surfaces and form part of a pattern that reflects a sequence-stratigraphic hierarchy. Spectral gamma-ray logs from uncored boreholes or weathered cliffsides and acquired without full petrographic descriptions can intersect low-angle faults such as thrusts. Our study demonstrates that bedding-parallel faults can be mistaken for flooding surfaces. We document the spectral gamma-ray response through a range of visually obvious and cryptic faults that may serve as proxy examples for other areas. Finally, we derive a preliminary generic model for the origin of spectral gamma-ray variations in faulted sandstones, limestones, and metamorphic successions. This shows why fluid-rock interactions along bedding-parallel zones of deformation generate elevated K and U and depressed Th/K and Th/U. Our observations may aid subsurface studies of the complex stratigraphy below thrusts.

Description: We analyzed a migrated three-dimensional (3-D) seismic reflection data set collected from Jackson County, Ohio, using volume-based voxel visualization technology. Adjusting the opacities of voxels in a time slab centered on the Precambrian reflector revealed a drainage channel system incised on the Ohio Precambrian surface, approximately 1460 m (4800 ft) below sea level. Formation sculpting of the Precambrian surface produced an image of 100-m (330-ft)-wide tributaries on the Precambrian unconformity joining to produce a 400-m (1320-ft)-wide channel roughly parallel to the subsurface trend of the Grenville front beneath Ohio. Broadening and splitting of the zero-phase seismic wavelet that defines the Precambrian reflector reveals the channels. The seismic signature is caused by thin-bed interference effects caused by reflections at the boundary between the channel fill with the overlying Mount Simon Formation and the boundary with the underlying Precambrian surface. The seismic images, therefore, locate a new lithologic unit in the Ohio subsurface. The channels are older than the overlying Mount Simon Formation and so must be at of least Middle Cambrian age. The channel morphology indicates flow in the direction of the Rome trough, approximately 60 km (37 mi) to the south, likely transporting sediment to that basin. Given the tiny volume of Ohio sampled by 3-D seismic methods, such buried channels must be common on the Precambrian surface. Justin Reuter is a geophysicist at Anadarko Petroleum Corporation. He received a B.S. degree in geology from Central Michigan University and an M.S. degree in geophysics from Wright State University. He is actively working on the Gulf of Mexico shelf. His interests are seismic data processing and interpretation.Doyle R. Watts is an assistant professor of geophysics at Wright State University. He received a B.S. degree in physics from Ohio State University in 1972, an M.S. degree in geology from Ohio State University in 1975 and a Ph.D. in geology from the University of Michigan in 1979. He was a postdoctoral fellow at the University of Leeds and lecturer in geophysics at Glasgow University. He has carried out geophysical investigations in Antarctica, North America, Scotland, England, and Tibet. His interests are seismic data processing and interpretation and remote sensing.

Description: Restoration of a 375-km (230-mi)-long section across the Kwanza Basin, Angola, shows three stages of deformation detaching on Aptian salt, each caused by basement tectonics. First, tilting related to postrift thermal subsidence initiated early Albian deformation, shortly after salt deposition ended. Deformation waned in the late Albian, probably because of thinning of salt lubricant beneath the extensional province. The second phase of deformation was triggered by hitherto unrecognized crustal uplift beneath the continental rise around 75 Ma (Campanian). Uplift led to salt extrusion and seaward advance of the Angola salt nappe over the abyssal plain. Exposure of the nappe toe removed the buttress provided by abyssal-plain cover, which rejuvenated seaward translation. Third, Miocene basement uplift below the shelf steepened the bathymetric slope and greatly accelerated downslope translation. This deformation is now slowing because accelerated sedimentation on the abyssal plain reduced the relief of the system and blocked salt-nappe advance. Minor changes in basin configuration led to profound changes in detached deformation. Miocene uplift was only a few hundred meters on the shelf, but this was sufficient to destabilize the system and increase the translation rate from 300 to 3200 m/m.y. (980 to 10,500 ft/m.y.) Deposition of 600 m (2000 ft) of sediment on the abyssal plain in the upper Miocene shifted contractional deformation 150 km (95 mi) landward. We conclude that driving and resisting forces have been precariously balanced for much of the Kwanza Basin's history. Mike Hudec received his Ph.D. from the University of Wyoming. He has worked for Exxon Production Research and taught at Baylor University. He joined the Bureau of Economic Geology in 2000, where he is codirector of the Applied Geodynamics Laboratory. His current research interests include palinspastic restoration of salt structures, salt-sheet emplacement mechanisms, and minibasin initiation.Martin Jackson received his Ph.D. from the University of Cape Town in 1976, taught at the University of Natal, and joined the Bureau of Economic Geology in 1980. He established and codirects the Applied Geodynamics Laboratory. His current research interests include salt-sheet emplacement mechanisms, passive-margin tectonics, and behavior of salt in orogenic belts.

Description: Late Quaternary shallow biogenic gas reservoirs have recently been discovered and exploited in the coastal Hangzhou Bay area, northern Zhejiang Province, eastern China. The river in this area strongly incised the underlying old beds during a period of glacial maximum, which resulted in the formation of the Qiantangjiang and the Taihu incised valleys. These incised valleys were filled with fluvial sediments and buried by marine sediments during the postglacial period. Late Quaternary strata of the incised-valley area are composed of four sedimentary facies in ascending order: fluvial floor facies (IV), flood-plain facies (III), sublittoral-marine bay facies (II), and estuarine facies (I). All commercial gas fields occur in flood-plain sand bodies of incised valleys. The bodies are buried 30–60 m (98–197 ft) deep and are 3.0–7.0 m (9.8–23 ft) thick, with a maximum thickness of more than 10 m (33 ft). They are surrounded by impermeable clays. Rapid deposition of overlying sublittoral-marine bay sediments supplied not only abundant gas sources, but also good preservation conditions. The main hydrocarbon sources are dark gray clays of the flood-plain facies and gray muds of the sublittoral-marine bay facies. Sediments of both facies have organic carbon content generally more than 0.4%. Shallow biogenic gas fields and deep gas fields require vastly different drilling and completion techniques. Drilling and completion costs are much lower for the biogenic gas fields. Quaternary incised valleys and flood plains other than Hongzhou Bay in coastal areas of eastern China are promising targets of further exploration for shallow biogenic gas. C. M. Lin received a B.Sc. degree from Daqing Petroleum Institute in 1986. He obtained his M.Sc. degree from the Petroleum University of China in 1995 and his Ph.D. from the Tongji University in 1997. Lin is currently an associate professor at the Department of Earth Sciences at Nanjing University, where he studies sedimentology and petroleum geology.L. X. Gu received a B.Sc. degree from Peking University in 1967. He obtained his M.Sc. degree and his Ph.D. from Nanjing University in 1982 and 1985, respectively, and is currently a professor in the Department of Earth Sciences, Nanjing University. His principal research interests are the formation mechanism of oil and gas reservoirs in volcanic rocks. G. Y. Li received a B.Sc. degree from Daqing Petroleum Institute in 1984. He is now a Ph.D. student in the Department of Earth Sciences at Nanjing University. Li's current research deals with the formation mechanism of gas reservoirs. Y. Y. Zhao received her B.Sc. degree from Petroleum University of China in 2001 and is currently a M.Sc. student at Nanjing University. Her interest is now in the study of sedimentology. W. S. Jiang received a B.Sc. degree in petroleum geology in 1958 from Peking Geology University. He has been working as a geologist with the Zhejiang Branch Company of PetroChina since then.

Description: We use established analytical methods and numerical computation techniques to model the net effect on sandstone permeability induced by realistic arrays of low-permeability deformation bands. Our two-dimensional approach, based on homogenization theory, allows the local permeability impact of any deformation band pattern to be calculated and provides a framework within which to extrapolate the effects of systematic patterns to the reservoir-simulation scale. We demonstrate the method for each of three characteristic deformation band patterns—parallel, cross-hatch, and anastomosing—exposed in the Aztec Sandstone at the Valley of Fire, Nevada, which provides an excellent exhumed analog for active sandstone reservoirs. Our analysis indicates that these systematic and extensive deformation band patterns can reduce overall permeability by as much as two orders of magnitude at scales relevant to reservoir production while inducing similar magnitudes of permeability anisotropy. We conclude that accounting for the aggregate effects of deformation bands in the subsurface would significantly improve reservoir simulation and production management in sandstone.

Description: Debate over whether human activity causes Earth climate change obscures the immensity of the dynamic systems that create and maintain climate on the planet. Anthropocentric debate leads people to believe that they can alter these planetary dynamic systems to prevent what they perceive as negative climate impacts on human civilization. Although politicians offer simplistic remedies, such as the Kyoto Protocol, global climate continues to change naturally. Better planning for the inevitable dislocations that have followed natural global climate changes throughout human history requires us to accept the fact that climate will change, and that human society must adapt to the changes. Over the last decade, the scientific literature reported a shift in emphasis from attempting to build theoretical models of putative human impacts on climate to understanding the planetwide dynamic processes that are the natural climate drivers. The current scientific literature is beginning to report the history of past climate change, the extent of natural climate variability, natural system drivers, and the episodicity of many climate changes. The scientific arguments have broadened from focus upon human effects on climate to include the array of natural phenomena that have driven global climate change for eons. However, significant political issues with long-term social consequences continue their advance. This paper summarizes recent scientific progress in climate science and arguments about human influence on climate.

Description: Chemostratigraphy and heavy-mineral techniques have been applied to the Lower Cretaceous Basal Quartz in the Western Canada sedimentary basin. The aim of the study is to demonstrate that these two techniques can be used to help understand the complex stratigraphy of reservoirs deposited in low-accommodation fluvial settings. The Basal Quartz is an ideal unit to demonstrate their applicability in stratigraphic studies of hydrocarbon reservoirs because extensive mapping and petrographic studies have enabled the establishment of a rigorous stratigraphic framework despite its complexity resulting from deposition in a low-accommodation fluvial setting. The three component units analyzed in the Basal Quartz (Horsefly unit, Bantry–Alderson–Taber [BAT] unit, and Ellerslie unit) each have unique geochemical and heavy-mineral characteristics. Chemostratigraphic analysis shows that silty claystones from the Horsefly, BAT, and Ellerslie units have distinctly different geochemistry from one another, with the variations being caused by changes in clay mineralogy and other components, such as feldspar, apatite, and zircon. The geochemistry also suggests periodic volcanogenic input influenced the silty claystones of the Basal Quartz. Heavy-mineral analysis shows that sandstones from the three units can be distinguished on the basis of ratio parameters, such as apatite/tourmaline, rutile/zircon, and zircon/tourmaline, which are controlled by differences in provenance and intensity of weathering during transport. Ken Ratcliffe is the chief executive officer of Chemostrat Inc. and the director of its parent company Chemostrat Ltd. Prior to cofounding Chemostrat Ltd. in 1994, Ken gained a B.Sc. degree (geology) from Imperial College, London, United Kingdom (1984) and a Ph.D. from Aston University, Birmingham, United Kingdom (1987). He then worked as a lecturer at the University of Kingston-upon-Thames before moving into the service sector in 1989.Milly Wright is currently country manager for Chemostrat Inc. based in Houston, Texas. Prior to joining Chemostrat in 2000, Milly gained a B.Sc. degree (geology) from the University of Leicester, United Kingdom (2000). Milly is also currently studying for a Ph.D. in Houston. Claire Hallsworth is a director of HM Research Associates, applying heavy-mineral stratigraphy in provenance and correlation projects. She joined HM Research in 2001 after a 15-year career in the British Geological Survey. She was educated at Leeds University and has published several papers on heavy-mineral provenance and correlation studies. Andy Morton formed HM Research Associates, a research company that undertakes provenance and correlation studies for the hydrocarbon industry, in 2000. He also has a part-time research position in the Department of Geology and Petroleum Geology at the University of Aberdeen. He was educated at Oxford University and has a long publication list, focusing on heavy-mineral studies. Brian Zaitlin held a variety of research and development, technical service, training, and front-line exploration/development positions with Gulf Canada, Esso, PanCanadian, and EnCana Corporation. Brian obtained his B.Sc. degree (geology) from Concordia (1979), his M.Sc. degree in geology/sedimentology from the University of Ottawa (1981), and his Ph.D. at Queen's Uni versity (1987). Brian left EnCana in 2003 to join Suncor Energy's Natural Gas and Renewable Energy Division in their Prospect Generation Services group. Dan Potocki is presently employed as a rock characterization advisor at EnCana. His work focuses primarily on reducing rock-related risk in integrated geoengineering studies. Dan was previously employed as a research geologist at Shell, Petro-Canada, and PanCanadian. He has published several articles in a variety of geological and engineering journals. Dan has an honors geology degree from McMaster University. Dave Wray attained his Ph.D. in 1991 from a geochemical study of bentonites in Upper Cretaceous chalks of northwest Europe. He is currently a senior lecturer at the University of Greenwich, where he manages the geochemical laboratories and lectures in applied geochemistry and sedimentology. His research interests include the application of sedimentary geochemistry to stratigraphic problems.

Description: The Lower Cretaceous Woburn Sands (Lower Greensand Group) in southern England constitutes one of the most intensively studied tidal sandstone outcrops for sedimentological and reservoir analog studies. Most recent workers have interpreted the whole 30–60-m (100–200-ft)-thick succession around Leighton Buzzard as representing an ancient tide-dominated estuary. However, unequivocal estuary characteristics are limited to the lowermost part (about 15–20 m [50–66 ft]). We suggest that a significant portion of the Woburn Sands, and most of the middle part, was formed in a tide-dominated marine embayment. Hence, the vertical facies change from the lower to middle part of the Woburn Sands is interpreted as a change from (1) a narrow estuary to (2) a broad marine embayment. The Wash embayment in eastern England is a striking modern analog; it receives most of its sediments and waters from marine sources and is largely filled with nondiluted seawater. Moreover, the Holocene transgressive history of The Wash is remarkably similar to the transgressive evolution of the Woburn Sands. Early estuarine sequence models predict landward translation of facies zones along the valley thalweg during transgression, but eventual facies translation in the strike direction has not been fully documented or discussed. An embayment facies that is not commonly confined in the early incised valley can occur vertically between the estuarine valley fill and marine shelf deposits and is probably underrepresented in current models. However, this segment of the transgression, comprising along-strike bay expansion and the development of a broad marine embayment, may be more important than previously thought. Shuji Yoshida has a B.Eng. degree (mining engineering) from Kyushu University, Japan, an M.Sc. degree (petroleum geology) from Imperial College, United Kingdom, and a Ph.D. (basin analysis) from Toronto University, Canada. He held industry and postdoctoral positions in reservoir characterization (Imperial College), coastal geomorphology (Royal Holloway, University of London), and hydrocarbon exploration (University of Wyoming). His main interest is shallow-marine and nonmarine sedimentology.Howard Johnson holds the Shell Chair of Petroleum Geology at Imperial College. His interests include clastic sedimentology, sequence stratigraphy, reservoir characterization, and basin studies. He spent 15 years with Shell working in research, exploration, and development geology and engineering. He holds a B.Sc. degree in geology from the University of Liverpool and a D.Phil. in sedimentology from the University of Oxford. Ken Pye has B.A. and M.A. degrees from Oxford University and a Ph.D. and an Sc.D. from Cambridge University. He has been professor of environmental geology at Royal Holloway since 1999. He was Natural Environment Research Council (NERC) and then Royal Society Research Fellow at Cambridge University, then lecturer, reader, and professor at Reading University. His publications include 11 books and more than 180 papers. Richard Dixon joined BP in 1989 with a Ph.D. in marine geology and volcaniclastic sedimentology. He spent several years working on deep-water sediments and published several papers in this field, notably on postdepositional modification and sandstone intrusion. Since 1996, he has worked almost exclusively on paralic sequences, including examples from the North Sea, Alaska, Algeria, east Siberia, Sakhalin, and Trinidad.

Description: Significant heterogeneity in petrophysical properties, including variations in porosity and permeability, are well documented from carbonate systems. These variations in physical properties are typically influenced by original facies heterogeneity, the early diagenetic environment, and later stage diagenetic overprint. The heterogeneities in the Mississippian Madison Formation in the Wind River basin of Wyoming are a complex interplay between these three factors whereby differences from the facies arrangement are first reduced by pervasive dolomitization, but late-stage hydrothermal diagenesis introduces additional heterogeneity. The dolomitized portions of the Madison Formation form highly productive gas reservoirs at Madden Deep field with typical initial production rates in excess of 50 MMCFGD. In the study area, the Madison Formation is composed of four third-order depositional sequences that contain several small-scale, higher frequency cycles. The cycles and sequences display a facies partitioning with mudstone to wackestone units in the transgressive portion and skeletal and oolitic packstone and grainstone in the regressive portions. The grainstone packages are amalgamated tidally influenced skeletal and oolitic shoals that cover the entire study area. The basal three sequences are completely dolomitized, whereas the fourth sequence is limestone. The distribution of petrophysical properties in the system is influenced only in a limited manner by the smaller scale stratigraphic architecture. Porosity and permeability are controlled by the sequence-scale stratigraphic units, where uniform facies belts and pervasive dolomitization result in flow units that are basically tied to third-order depositional sequences with a thickness of 65–100 ft (20–30 m). The best reservoir rocks are found in regressive, coarse-grained dolomites of the lower two sequences. Although the amalgamated shoal facies is heterogeneous, dolomitization decompartmentalized these cycles. Fine-grained sediments in the basal transgressive parts of these sequences, along with caliche and chert layers on top of the underlying sequences, are responsible for a decrease of porosity toward the sequence boundaries and potential flow separation. Good reservoir quality is also found in the third sequence, which is composed of dolomitized carbonate mud. However, reservoir-quality predictions in these dolomudstones are complicated by several phases of brecciation. The most influential of these brecciations is hydrothermal in origin and partly shattered the entire unit. The breccia is healed by calcite that isolates individual dolomite clasts. As a result, the permeability decreases in zones of brecciation. The late-stage calcite cementation related to the hydrothermal activity is the most important factor to create reservoir heterogeneity in the uniform third sequence, but it is also influential in the grainstone units of the first two sequences. In these sequences, the calcifying fluids invade the dolomite and partly occlude the interparticle porosity and decrease permeability to create heterogeneity in a rock in which the pervasive dolomitization previously reduced much of the influence of facies heterogeneity. Hildegard Westphal studied geology in Tübingen, Brisbane, and Kiel, where she received her Ph.D. in 1997. After a postdoctoral position at Rosenstiel School for Marine and Atmospheric Sciences, University of Miami, she became an assistant professor at Hannover University. Currently, she is a member of the Paleontology Department at Erlangen University. Her work focuses on early diagenesis of carbonates; the genesis, diagenesis, and paleoenvironmental record of limestone-marl alternations; and paleoecological interpretation of carbonate platforms.Gregor Eberli received his Ph.D.s from the Swiss Institute of Technology (ETH), Zürich, Switzerland, in 1985 and the University of Miami in 1991. With his colleagues at the Comparative Sedimentology Laboratory, he conducts research in sedimentology, stratigraphy, geochemistry, and petrophysics of modern and ancient carbonates. In several projects, he investigated the influence of sea level changes on sedimentary architecture. He was an AAPG Distinguished Lecturer in 1996–1997 and a Joint Oceanographic Institutions/U.S. Science Advisory Committee Distinguished Lecturer in 1998–1999. Langhorne Smith currently heads the Reservoir Characterization Group at the New York State Museum. He holds a B.S. degree from Temple University, a Ph.D. from Virginia Tech, and did postdoctoral work at the University of Miami. He also worked for Chevron as a development geologist for two years. His current research interests are in carbonate reservoir characterization and hydrothermal alteration of carbonate reservoirs. G. Michael Grammer is an associate professor at Western Michigan University. His research includes high-resolution carbonate sequence stratigraphy and early diagenesis and their application to reservoir characterization. He was an AAPG Distinguished Lecturer for 2002–2003 and is a coleader of AAPG's modern carbonate field course. Previously, he was a senior research associate for Texaco and has consulted for domestic and international oil companies. He received his Ph.D. from the University of Miami in 1991. Jason Kislak received his bachelor's degree from Franklin & Marshall College in Lancaster, Pennsylvania. He is currently working toward his master's degree at the Rosenstiel School of Marine and Atmospheric Science at the University of Miami.

Description: Beaufortian strata (Jurassic–Lower Cretaceous) in the National Petroleum Reserve in Alaska (NPRA) are a focus of exploration since the 1994 discovery of the nearby Alpine oil field (〉400 MMBO). These strata include the Kingak Shale, a succession of depositional sequences influenced by rift opening of the Arctic Ocean Basin. Interpretation of sequence stratigraphy and depositional facies from a regional two-dimensional seismic grid and well data allows the definition of four sequence sets that each displays unique stratal geometries and thickness trends across NPRA. A Lower to Middle Jurassic sequence set includes numerous transgressive-regressive sequences that collectively built a clastic shelf in north-central NPRA. Along the south-facing, lobate shelf margin, condensed shales in transgressive systems tracts downlap and coalesce into a basinal condensed section that is likely an important hydrocarbon source rock. An Oxfordian–Kimmeridgian sequence set, deposited during pulses of uplift on the Barrow arch, includes multiple transgressive-regressive sequences that locally contain well-winnowed, shoreface sandstones at the base of transgressive systems tracts. These shoreface sandstones and overlying shales, deposited during maximum flooding, form stratigraphic traps that are the main objective of exploration in the Alpine play in NPRA. A Valanginian sequence set includes at least two transgressive-regressive sequences that display relatively distal characteristics, suggesting high relative sea level. An important exception is the presence of a basal transgressive systems tract that locally contains shoreface sandstones of reservoir quality. A Hauterivian sequence set includes two transgressive-regressive sequences that constitute a shelf-margin wedge developed as the result of tectonic uplift along the Barrow arch during rift opening of the Arctic Ocean Basin. This sequence set displays stratal geometries suggesting incision and synsedimentary collapse of the shelf margin. Houseknecht joined the U.S. Geological Survey in 1992, serving as energy program manager until 1998. He has worked on Alaska North Slope basin analysis and petroleum resource assessment since 1995. Previously, Houseknecht was a professor of geology at the University of Missouri (1978–1992) and a consultant to the oil industry. He holds geology degrees from Penn State University (B.S. degree and Ph.D.) and Southern Illinois University (M.S. degree).Bird specializes in the petroleum geology of northern Alaska, where his experience spans more than 40 years. Currently, he is the leader of the U.S. Geological Survey Alaska Petroleum Studies Project. With interests primarily in stratigraphy and sedimentology, he has been extensively involved in petroleum resource assessments. He holds geology degrees from Oregon State University (B.S. degree) and the University of Wisconsin (M.S. degree and Ph.D.).

Description: Controls on oil family distribution in tectonically complicated, nonmarine, petroliferous basins are commonly difficult to isolate because of the varying ages of potential source rocks, the complex assemblage of organic-rich sedimentary facies, and the geographic variability of burial histories. The Turpan-Hami basin of northwestern China is an oil-bearing intermontane basin where stratigraphic, sedimentologic, and geochemical controls are sufficient to address each of these issues independently and to determine how they influence the current distribution and composition of liquid hydrocarbons. Source rock age is one of three major statistically significant discriminators affecting oil family composition. Both Lower/Middle (Lower or Middle) Jurassic and Upper Permian rocks are important source rocks for the basin. A newly developed diterpane biomarker parameter can distinguish Permian rocks and their correlative oils from Jurassic coals and mudrocks and their derivative oils. Source facies is a second key control on petroleum occurrence and character. A variety of biomarker parameters that reflect source rock depositional conditions are indexed to rock samples from interpreted depositional environments. By erecting rock-to-oil correlation models, the biomarker parameters separate oil families into end-member groups: group 1 oils = Lower/Middle Jurassic peatland/swamp facies (high land-plant input, less reducing conditions), group 2 oils = Lower/Middle Jurassic profundal lacustrine facies (high algal input, more reducing conditions), and group 3 oils = Upper Permian lacustrine facies (high algal, stratified, anoxic conditions). Burial history exercises a third major control on petroleum distribution. Source rock maturation modeling can demonstrate that relatively uninterrupted burial in the asymmetrically subsiding northern Turpan-Hami area (Taibei depression) exhausted Upper Permian-sourced rocks by the Late Cretaceous, which led to southward migration of Upper Permian–sourced oils (group 3) into Triassic reservoirs of southern and southwestern Turpan-Hami (Tainan and Tokesun depressions). Subsequent to uplift of the central basin thrust that currently partitions Taibei from Tainan, Lower/Middle Jurassic–sourced oils were expelled in the Taibei depression by Paleocene–Eocene time, which locally charged Jurassic and Cretaceous reservoirs (groups 1 and 2), forming Turpan-Hami's largest oil accumulations in the basin. Todd attained a B.S. degree in earth sciences from the University of California at Santa Cruz (1994) and a Ph.D. in geological sciences at Stanford University (2000). His dissertation focused on tectonics, sedimentology, organic geochemistry, and petroleum systems of the Turpan-Hami basin of northwestern China. He is currently employed by Anadarko Petroleum, in Houston, Texas, where he is part of a basin studies team investigating basins and play types in the greater Rocky Mountains, as well as international arenas in southeast Asia.David A. Zinniker is a Ph.D. candidate in the Department of Geological and Environmental Sciences at Stanford University. His research focuses on molecular fossils of plants and algae and their bearing on ecology, evolution, depositional systems, and petroleum geology. His future projects include using molecular and macromolecular markers to study current ecological processes and events deep in geologic time. J. Michael Moldowan attained a B.S. degree in chemistry from Wayne State University in 1968 and a Ph.D. in chemistry from the University of Michigan in 1972. Following a postdoctoral fellowship in marine natural products with Carl Djerassi at Stanford University, he joined Chevron's Biomarker Group in 1974. Moldowan joined the Department of Geological and Environmental Sciences of Stanford University as professor (research) in 1993. Cheng Keming received his degree from China Geology University in 1958. He is currently a senior geologist and professor for the Research Institute of Petroleum Exploration and Development for the China National Petroleum Corporation. He specializes in coal-generating geochemistry and petroleum resource evaluation. Su Aiguo received his degrees from the Jianghan Petroleum University (currently named Yangtze University) in 1986 and the Graduate School of the Research Institute of Petroleum Exploration and Development of the China National Petroleum Corporation in 1989. He worked as a petroleum engineer for the China National Petroleum Corporation and is currently a senior geologist at the Research Institute of Petroleum Exploration and Development of PetroChina. He specializes in petroleum geochemistry.

Description: We introduce a seismic-sedimentological approach for mapping high-frequency (fourth-order) sequences and systems tracts using well and three-dimensional seismic data. Key techniques include (1) conditioning seismic data to log lithology by 90° phasing for better well-log integration and (2) imaging and interpreting the sequential, planoform geomorphology of the depositional systems. We recommend a new interpretation procedure that shifts the emphasis of high-frequency sequence-stratigraphic studies from interpreting vertical seismic sections to analyzing more horizontal, high-resolution, seismic-geomorphologic information. This case study shows that stratal slicing in lithology-conditioned seismic data provides sequential seismic imagery of generally contemporaneous depositional systems. This imagery, in turn, serves as a basis for recognizing and mapping high-frequency systems tracts, sequence boundaries, and sequences in a geologic-time domain. In Miocene strata of offshore Louisiana, fourth-order sequences or sequence sets from well data can be seismically mapped at a resolution equivalent to 30 ft (10 m) in thickness from a 30-Hz dominant-frequency seismic data set. The resolution is sufficient for an accurate reconstruction of the high-frequency sequence-stratigraphic framework in the region of seismic coverage outside well control. Hongliu Zeng has been a research scientist for the Bureau of Economic Geology, Jackson School of Geosciences, University of Texas at Austin, since 1997. His research interests include seismic sedimentology, seismic stratigraphy, and special seismic processing, as applied to petroleum prospecting. He earned his B.S. (1982) and M.S (1985) degrees in geology from the Petroleum University of China and his Ph.D. (1994) in geophysics from the University of Texas at Austin.Tucker F. Hentz is a research associate at the Bureau of Economic Geology, Jackson School of Geosciences, University of Texas at Austin, which he joined in 1982. He graduated cum laude with a B.A. degree in geology from Franklin & Marshall College in 1977 and received his M.S. degree in geology from the University of Kansas in 1982. His research interests include the regional sequence stratigraphy of gas-bearing successions in the Anadarko basin, Rio Grande Embayment, and Gulf Coast Basin.

Description: Jurassic sandstones on the Colorado Plateau have been variably bleached through interaction with hydrocarbon-bearing solutions or other reducing agents. Deformation bands in the Navajo Sandstone have a variety of colors in comparison with the host rock color that indicate the timing of bleaching relative to deformation-band formation. White deformation bands in red sandstone indicate that deformation bands were likely permeable at an early dilatant stage in their development history. Field characteristics, petrography, bulk rock chemistry, clay mineralogy, and geochemical modeling show that bleached deformation bands experienced an episode of chemical reduction where fluids removed some iron and left the remaining iron as pyrite and magnetite. Mass-balance calculations show that as much as 10 kg of chemically reducing fluid per 100 g of rock (1500 pore volumes of fluid) are necessary to remove 0.1 wt.% iron from a deformation band. These large pore volumes suggest that moving, reducing solutions regionally bleached the sandstone white, and bleached deformation bands resulted where deformation bands provided localized fluid access to unbleached, red sandstone during an initial dilatant stage. Alternatively, access of reducing soil solutions may be provided by gravity-driven, unsaturated flow in arid to semiarid vadose zones. Color and chemical composition is a valuable index to the pathway and timing of hydrocarbon movement through both host rocks and deformation bands. William T. Parry is professor emeritus of geology and geophysics at the University of Utah. Former positions include associate professor of geosciences at Texas Tech University, Lubbock, Texas, and exploitation engineer for Shell Oil Company, Midland, Texas. He received his B.S. and M.S. degrees and his Ph.D. in geological engineering from the University of Utah. His research interests are geochemistry and mineralogy related to faults and ore deposits.Marjorie A. Chan is professor of geology at the University of Utah, where she joined the faculty in 1982 and currently serves as department chair. She received her B.S. degree from the University of California, Davis, and her Ph.D. from the University of Wisconsin, Madison. Her current research focuses on sedimentology and stratigraphy in Mesozoic deposits of the Colorado Plateau. Brenda Beitler is currently a Ph.D. candidate in the Department of Geology and Geophysics at the University of Utah. She earned a B.S. (1998) degree and an M.S. (2000) degree in earth sciences from the University of California, Santa Cruz. Her thesis research focuses on color variations and iron mineralization resulting from micro- to regional-scale fluid flow in the Navajo Sandstone.

Description: Reservoirs in the lower Pennsylvanian Morrow Formation of eastern Colorado, southwestern Kansas, and northwestern Oklahoma have produced greater than 8 tcf of gas and 200 million bbl of oil. This prolific depositional system produces from reservoirs representing a range of depositional environments from updip, fluvial-dominated, incised-valley fills to deep-water basin-floor systems. The valley fills of the Morrow Formation are of particular significance because they can be mapped in great detail from subsurface control over very long distances. Facies distributions in the valleys change systematically downdip. As a result, reservoir characteristics and trapping mechanisms vary with these changes in internal valley stratigraphy. This paper focuses on the reservoir geology of Nicholas and Liverpool Cemetery fields. These fields produce gas from the extreme downdip region of an incised-valley-fill system in the lower Morrow Formation. The valley systems in this downdip region are deeper and wider and demonstrate greater marine influence than the updip regions of the valley systems farther north and into the hinterland. Compartmentalization in these downdip reservoirs differs significantly from updip valley-fill reservoirs. The reservoirs in this downdip region are more highly compartmentalized because the dominant reservoir facies in these fields is a series of bayfill delta deposits. These deposits are isolated by shale deposits in the valley. This depositional setting contrasts markedly with predominantly fluvial reservoirs in updip regions of the valleys. Understanding the scale, geometry, and internal complexity of this depositional system is important because the associated sandstones are important gas reservoirs in southwest Kansas. Cores, wire-line logs, pressure data, and production data collected from the Morrow Formation at Nicholas and Liverpool Cemetery fields provide valuable information from which to describe and interpret this downdip valley fill. This paper describes the downdip incised-valley-fill reservoirs in this producing complex and documents the trapping relationships of these reservoirs and their production characteristics. David Bowen received his B.S. degree from Hobart College in 1978, his M.S. degree from Montana State University in 1980, and his Ph.D. from the University of Colorado in 2001. He is a consulting petroleum geologist and is an affiliate faculty member at Montana State University. His current work focuses on the application of stratigraphy to exploration and exploitation problems in the western United States. His research interests include sequence stratigraphy, basin analysis, and the study of incised-valley-fill systems. David will be an AAPG distinguished lecturer in 2003–2004.Paul Weimer holds the Bruce D. Benson Endowed Chair in the Department of Geological Sciences at the University of Colorado, Boulder, and serves as director of the Energy and Minerals Applied Research Center. He is the current treasurer of the AAPG. In 2004, he will give the Society of Exploration Geophysicists Distinguished Instructor Short Course.

Description: Oolitic carbonates and associated rocks in the San Andres Formation produce hydrocarbons at Olson field, west Texas. Mudstones, dolomitized fusulinid-peloid packstones and wackestones, ooid-peloid grainstones and packstones, and minor siliciclastic sediments occur in the field. The reservoir is stratigraphically compartmentalized by lenticular oolite deposits that are overlain by algal-laminated mudstones and siltstones. Pore-filling anhydrite cement, common in all lithologies, adds to porosity heterogeneity. Interwell communication is poor, as indicated by variable bottomhole pressures and erratic waterflood response. A medium-radius lateral hole was drilled to a total depth approximately 50 ft (15 m) from an offset vertical well. At this depth, the horizontal well intersected a previously existing artificial fracture that occurred in the nearby vertical well. The intersection of this fracture by the lateral borehole had a significant economic impact. The production rate in the vertical well jumped from a few barrels per day to an average of 70 BOPD and less than 20 BWPD. The ensuing years maintained relatively high flow rates. Projected incremental oil recovery is 153,000 bbl, roughly equivalent to production from an average well drilled during the early life of the field. Other unsuccessful horizontal wells have been drilled at Olson field, but they have not targeted preexisting hydrofractures in offset vertical wells. Therefore, the concepts presented in this paper have not been retested. This approach, intentionally drilling a drainhole to intersect a preexisting hydrofracture, could add new life to many older, compartmentalized reservoirs. Neil F. Hurley is a professor of geology at the Colorado School of Mines. He received B.S. degrees from the University of Southern California (1976), an M.S. degree from the University of Wisconsin, Madison (1978), and a Ph.D. from the University of Michigan (1986). He is a past editor of AAPG and has been an AAPG and Society of Petroleum Engineers distinguished lecturer. Specialties include carbonate geology and reservoir characterization.Sara Ustabas has worked for Turkiye Petrolleri A. O. as an exploration geologist since 1999. She received her B.S. degree from Karadeniz Technical University (1996), and she completed her M.S. degree at the Colorado School of Mines (1999).

Description: In offshore East Kalimantan, Indonesia, three-dimensional seismic reflectors can be traced downslope from a lowstand delta to a basin-floor fan, giving insight into depositional processes controlling the distribution of sands that serve as hydrocarbon reservoirs in many ancient deep-water settings. The studied interval includes the last three Pleistocene cycles (10–330 ka; each ∼110 k.y. in duration). Cycles on the shelf are dominated by progradational packages deposited during highstands and falling eustatic sea level. Progradational packages are separated by parallel reflectors and carbonate buildups of the transgressive systems tracts. During the last two lowstands of sea level (∼18 and ∼130 ka), coarse clastics were not deposited in deep-water environments because growth faults and regional subsidence prevented lowstand deltas from reaching the slope. During the lowstand of sea level that ended at about 240 ka, a delta prograded over the previous shelf edge, and sand-rich sediments spilled onto the slope. Strata on the slope and basin floor show how a deep-water depositional system evolved during a single cycle of eustatic sea level. A canyon on the slope connects the 240-ka lowstand delta to a coeval basin-floor fan. The canyon has a sinuous, bipartite fill that consists of a lower, amalgamated channel complex and an upper channel-levee complex. The basin-floor fan formed at the toe of the slope also has two parts. The stratigraphically lower part of the basin-floor fan has broad lobes with relatively continuous reflectors. The stratigraphically higher part has a sinuous channel-levee complex that prograded over the lower fan and fed sheetlike lobes on the outermost fan. The amalgamated channel fills on the slope and sheetlike lobes on the basin-floor fan have moderate- to high-amplitude reflectors and are inferred to represent sand-rich, early lowstand deposits. The channel-levee complexes on the slope and basin floor are dominated by low-amplitude reflectors and are inferred to be mud-rich strata deposited during the late lowstand. Unlike classic sequence-stratigraphic models, these lowstand strata do not onlap the slope; instead, deep-water clastics extend from the last clinoforms of lowstand deltas. In this system, lowstand deltas determined when and where sand-rich sediments entered preexisting canyons on the slope to feed basin-floor fans. Art Saller currently works as a sedimentologist and stratigrapher for Unocal in Sugar Land, Texas. He received geology degrees from the University of Kansas (B.S., 1974–1978), Stanford University (M.S., 1980), and Louisiana State University (Ph.D., 1984). From 1984 to 1986, he worked for Cities Service Oil and Gas in Tulsa, Oklahoma, and joined Unocal in 1986.Jesse Noah has been with Unocal for 22 years and is currently Unocal's chief geoscientist for the Deep-Water Gulf of Mexico. Initially, he worked on the United States mid-continent and Gulf of Mexico shelf. He has worked on deep-water exploration and development projects in the Gulf of Mexico and Indonesia since 1996. Jesse received his B.S. degree in exploration geophysics from the University of Oklahoma. Alif Ruzuar graduated from the Bandung Institute of Technology, Indonesia, in 1998 with a B.S. degree in geology. He earned an M.Sc. degree in petroleum geoscience from the University of Brunei Darussalam (1999). Alif joined Unocal Indonesia in 2000 as a deep-water exploration geophysicist and is currently working as a development geophysicist for fields on the East Kalimantan shelf. Rhys Schneider received his B.S. degree in geological engineering from the Colorado School of Mines in 1978. He joined Unocal in 1980 and has worked as an exploration and development geologist in the Anadarko basin, Permian basin, and many other basins throughout the world. He currently specializes in detailed, seismic-defined, reservoir characterization for deep-water systems of the Kutei Basin, Indonesia.

Description: The Council Run field of north central Pennsylvania is one of the most productive natural gas fields in the central Appalachian basin. The field is enigmatic because of its position near the eastern edge of the Appalachian Plateau, where strata with reservoir potential elsewhere have low porosities and permeabilities or are poorly sealed. Council Run has four principal reservoir sandstones. The lower three occur in a distinct fourth-order type 1 stratigraphic sequence. The stacking pattern of sandstones in this sequence defines lowstand, transgressive, and highstand systems tracts. Core, well-log, and map interpretations reveal that the lowest interval consists of multiple coarsening-upward parasequences deposited in deltaic and nearshore environments of the lowstand systems tract during a forced regression. Most of these sandstones are lithic, and some are highly feldspathic. Productive sandstones display hybrid void textures that consist of reduced primary intergranular pores preserved, in part, by relatively early petroleum emplacement and secondary oversized fabric-selective pores. The generative potential of the organic matter in the potential source rocks is exhausted, but geochemical and petrographic evidences indicate that these black shales originally contained oil-prone kerogens and generated liquid hydrocarbons. Stable isotope geochemistry suggests that gases were generated by primary cracking of kerogens and/or by secondary cracking of oil between 320 and 290 Ma. Dispersive migration paths were both lateral and vertical because of compression associated with Alleghanian orogenesis. Most of the oil in the Devonian section was cracked to gas during deeper burial between 270 and 240 Ma. Christopher D. Laughrey is a senior geologic scientist with the Pennsylvania Geological Survey where he has worked since 1980. He also teaches a graduate course in sandstone petrology for the Department of Geology and Planetary Sciences at the University of Pittsburgh. Laughrey worked as a geophysical analyst for the Western Geophysical Company in Houston, Texas, before taking his present position in Pittsburgh, Pennsylvania. His special interests include isotope and organic geochemistry, sedimentary petrology, borehole geophysics, and geographic information system applications in the earth sciences.Dan A. Billman received his B.S. degree from the University of Toledo in 1986 and his M.S. degree from West Virginia University in 1989. Dan worked for Mark Resources Corporation and Eastern States Exploration Company prior to forming Billman Geologic Consultants, Inc., where he is president and principal geologist. Dan's current interests include geologic and economic evaluation of development and exploratory projects, especially in the Appalachian basin. Michael R. Canich has worked 26 years in the oil and gas industry, beginning with two years developing exploration prospects in the Gulf of Mexico. The last 24 years have been spent in the Appalachian basin exploring and developing natural gas in Silurian and Devonian aged tight gas sand reservoirs. He is currently the director of Reserve Development for Equitable Production Company in Pittsburgh, Pennsylvania.

Description: Mapping in the East Gobi basin, supplemented by seismic data, reveals a structural and burial history for basins adjacent to the Zuunbayan and Tsagaan Els oil fields. The tectonic framework was combined with available well and outcrop data to model the timing and magnitude of hydrocarbon generation. Five structural episodes are recognized: (1) pre-Jurassic northeast-directed shortening that formed the tectonic fabric; (2) Middle Jurassic to Early Cretaceous rifting along northeast trends that formed the subbasins of the East Gobi basin; (3) late Early Cretaceous north-south shortening and inversion on existing normal faults; shortening caused left-lateral and reverse displacements on northeast-trending faults; (4) middle Cretaceous uplift and erosion, followed by (5) east-west shortening and right-lateral movement on northeast faults. Folds formed by inversion over Middle Jurassic–Early Cretaceous normal faults. Modeling suggests that the bituminous member of the Zuunbayan Formation should be mature over large parts of the Unegt and Zuunbayan subbasins. Oil migrated from mature source areas toward several traps, including the Zuunbayan and Tsagaan Els fields. Modeling suggests that early oil (104–110 Ma) was generated in the Zuunbayan and Tsagaan Els area because of deep burial during the Cretaceous. Although generation began in the Early Cretaceous, peak generation in the Unegt subbasin occurred between 100 and 90 Ma. Generation continued at a decreasing rate up to the present day. Kerogen maturity (and oil field production) suggests that oil is the most likely product. Scoping calculations of hydrocarbon volumes generated indicate that the Unegt basin may have generated as much as 86 billion BOE. Gary Prost received his Ph.D. in geology from the Colorado School of Mines and works for ConocoPhillips Canada on development of the Parsons Lake gas field, Northwest Territories. Over 28 years in the energy industry, he has worked for the U.S. Geological Survey, Superior Oil, Amoco, and Gulf Canada and is author of Remote Sensing for Geologists and English–Spanish Glossary of Geoscience Terms .

Description: The Faeroe–Shetland Basin is part of a passive continental margin that formed as a result of multiphase extension associated with North Atlantic rifting during the Mesozoic and Paleocene. Breakup was followed by postrift subsidence during the latest Paleocene to late Eocene and the development of at least three 70–150-km (43–93-mi)-long, broadly north-south–orientated, slope canyons and linked terminal fans during the middle Eocene. The terminal fans filled northeast-southwest–striking basin-floor bathymetric depressions that had formed above the hanging walls of underlying, dormant northeast-southwest–trending Mesozoic extensional faults and adjacent half-graben depocenters. Compression during the middle and late Miocene caused contractional reactivation of the Mesozoic extensional faults and folding of the overlying uppermost Paleocene to middle Miocene postrift sediments into a series of 17 northeast-southwest–striking anticlinal domes. The switch from hanging-wall bathymetric depression during terminal fan deposition to anticlinal domal high during and after the middle to late Miocene compression has led to the present-day spatial coincidence of a potential hydrocarbon reservoir and an effective trap. The anticlines also acted as the foci for gas migration during or after compression (15 Ma to present). However, the timing of compression and differential uplift of the basin margins during the past 15 m.y., approximately 45 m.y. after the main phase of oil migration, may be a critical negative factor for oil exploration in this part of the basin. This hydrocarbon phase may have spilled during the structural reorganization, either updip into shallower traps or out of the hydrocarbon system via seeps. Richard Davies has a B.Sc. degree from the University of Reading (1990) and a Ph.D. from the University of Edinburgh, United Kingdom (1995). He joined Mobil North Sea in 1995 and worked on field development and exploration in the North Sea and west of Shetlands, United Kingdom, and then for ExxonMobil Exploration on acreage on the west Niger delta deep-water slope. In 2003, he was appointed senior lecturer at the School of Earth Sciences, Cardiff University, United Kingdom. His main interest is the use of 3-D seismic data for the investigation of sedimentary and deformational processes.Ian Cloke has a B.Sc. degree from the University of Durham and an M.Sc. degree and a Ph.D. from Royal Holloway, University of London, United Kingdom. He has worked as a geoscientist for Conoco, United Kingdom, LASMO, Mobil North Sea, and ExxonMobil Production. Since 2001, he has explored the deep overpressured Vicksburg and Frio of south Texas for tight gas plays. Joe Cartwright is a research professor in geophysics at the School of Earth Sciences, Cardiff University, United Kingdom. He holds an M.A. degree in geology and a Ph.D. in structural geology from Oxford University, United Kingdom. He worked for Shell International in the early 1980s as a seismic interpreter, with operational experience in Denmark and Brunei Darussalam. From 1989 to 1999, he was a senior lecturer at Imperial College, London. His main research interests have been in the analysis of basin deformation using 3-D seismic data, with specific focus on soft-sediment deformational processes and fluid flow. Andrew Robinson is a Ph.D. student at the School of Earth Sciences, Cardiff University, United Kingdom, investigating the stratigraphic evolution of the Faeroe–Shetland Basin during the Paleogene. He obtained his B.Sc. (1996) and MRes (1998) degrees from the University of Edinburgh (United Kingdom) and has also worked for Amerada Hess, coauthoring the Upper Jurassic chapter of The Millennium Atlas: The Petroleum Geology of the Central and Northern North Sea, United Kingdom. Charlie Ferrero recently completed his Ph.D. at Imperial College, London, investigating the application of a novel statistical method to the quantification of uncertainty in thermal history modeling for hydrocarbon exploration, with particular emphasis on defining practical guidelines for future use. He holds an M.Sc. degree in petroleum geology, also from Imperial College, and an M.A. degree from Cambridge University, United Kingdom.

Description: The Qaidam basin is a continental petroliferous basin located in northwest China. Its northern sector is an important hydrocarbon province, where one of the earliest oil discoveries in China was made. Although Mesozoic source rocks are understood to be important parts of Qaidam petroleum systems, the identification and distribution of Mesozoic source rocks in the subsurface are poorly understood. Middle Jurassic coal measures and associated shales have long been considered to be the primary Mesozoic source rocks for the northeastern Qaidam basin without any support from subsurface geochemical and geological data. However, new data have been gathered from earlier Mesozoic sediments that were penetrated by the Lengke-1 well, a deep scientific well with a total depth of 5200 m (17,060 ft). The well was drilled on the Lenghu structural belt in 1997 and documented other effective source rocks. Geochemical analyses indicate that Lower Jurassic mudstones are good to excellent source rocks for the commercial oil wells in the Lenghu area. The upper Middle Jurassic shales are very good source rocks for the commercial oil wells in the Yuka area. Two source rock intervals in the northeastern Qaidam basin allow for two petroleum systems to be distinguished, the Lower Jurassic–Lower Jurassic/Tertiary and Middle Jurassic–Upper Jurassic. The Lower Jurassic–Lower Jurassic/Tertiary petroleum system, with a geographical extent of 15,000 km2 (5800 mi2) and a cumulative amount of source rocks between 200 and 700 m (650 and 2300 ft), represents a favorable target for future exploration. The Middle Jurassic–Upper Jurassic petroleum system, however, may have a lower exploration potential because of a smaller area (1500 km2 [580 mi2]) and a thinner cumulative amount of source rocks (100–200 m [330–650 ft]). Yongtai Yang is a Ph.D. candidate at the University of Toronto, studying sequence stratigraphy and basin analysis. He received an M.S. degree in geology from the China Research Institute of Petroleum Exploration & Development (RIPED) in 1996. He worked as a petroleum geologist at RIPED from July 1996 to July 2003.Baomin Zhang received his M.S. degree in geology from the Beijing Normal University in 1989. He currently is a senior geologist focusing on sedimentology and petroleum geochemistry at RIPED. Before joining RIPED in 1994, he worked as an associate professor at the Beijing Normal University. Changyi Zhao received his Ph.D. in geology from the Chinese University of Mining and Technology in 1991. He currently is a senior geologist focusing on petroleum geochemistry and petroleum geology at RIPED. Tianguang Xu received his M.S. degree in geology from Kansas State University in 2001. He is currently a basin researcher with IHS Energy, focusing on Chinese basins.

Description: A detailed analysis of Oligocene Frio Formation intraslope, growth-faulted subbasins in the Corpus Christi, Texas, area indicates that deposition during relative lowstands of sea level was the main initiator, or trigger, of growth faulting. Lowstand depocenters on the low-gradient, upper continental slope comprising basin-floor fan facies, slope-fan systems, and prograding lowstand delta systems exerted sufficient gravity stress to trigger major sections of outer shelf and upper slope strata to fail and move basinward. The faults sole out deep in the basin, and rotation of hanging-wall blocks mobilized deep-water muds and forced the mud basinward and upward to form mud (shale) ridges that constitute the basinward flank of intraslope subbasins overlying footwall fault blocks. Sedimentation associated with third-order relative falls of sea level produced load stress that triggered a major regional syndepositional growth-fault system. Subbasins on the downthrown side of each arcuate fault segment that constitute a regional fault system are filled during the lowstands of sea level. Consequently, genetically similar but noncontemporaneous lowstand depositional systems filled each successive growth-faulted subbasin trend. The subbasin stratigraphy becomes younger basinward because the subbasin development and fill process extended the Frio shelf edge stepwise into the Oligocene Gulf of Mexico Basin, coinciding with relative third-order sea level cycles. The subbasins have been prolific petroleum targets for decades and are now the focus of prospecting for deep gas. Lowstand sandstones are principal reservoirs, and synsedimentary tectonics produced anticlinal and fault traps and associated stratigraphic pinch-out traps on the flanks of the structures. Understanding the origin of the faulted subbasins and their chronostratigraphic relationships and depositional processes provides a perspective that can improve deep gas exploration. Frank Brown received his B.S. degree in geology and chemistry from Baylor University in 1951 and his M.S. degree and his Ph.D. from the University of Wisconsin, Madison, in 1953 and 1955, respectively. Frank worked for Standard Oil of Texas (Chevron) in 1955–1957, the Bureau of Economic Geology (BEG) in 1957–1960 and 1966–1989, and as an international consultant in 1989–1999. From 1960 to 1966, he was associate professor at Baylor University. He was professor of geological sciences at the University of Texas at Austin in 1971–1989 and emeritus professor in 1989–1999. Since 1999, he has been a research professor at BEG, where he continues his studies of the sequence stratigraphy of the Gulf Coast of Texas and Mexico.Robert Loucks is a senior research scientist at the Bureau of Economic Geology, working on siliciclastic and carbonate reservoir characterization. He was the recipient of the 1999 AAPG Wallace E. Pratt Memorial Award for Best Paper, the 1982 SEPM Excellence of Presentation Award, and the 1991 SEPM Excellence of Poster Presentation Award. Bob served as the Mideast AAPG Dean A. McGee International Distinguished Lecturer in 1999. Ramon Treviño received his B.S. degree in geology (Texas A&I University, 1983) and his M.S. degree in geology (University of Texas at Arlington, 1988). He worked for Mobil from 1988 to 1992 and received an M.B.A. degree from the University of Oklahoma in 1994. Since 1995, he has worked on sequence-stratigraphic reservoir characterization at the Bureau of Economic Geology. Ursula Hammes obtained her diploma in geology from the University of Erlangen, Germany, in 1987, and her Ph.D. from the University of Colorado at Boulder in 1992. She spent 10 years in industry and joined the Bureau of Economic Geology in 2002 as a research associate. Her main research focus is in clastic and carbonate sequence stratigraphy, depositional systems, and image analysis.

Description: The 87Sr/86Sr compositions of formation waters that were collected from 71 wells producing from a Pennsylvanian carbonate reservoir in New Mexico display a well-defined distribution, with radiogenic waters (up to 0.710129) at the updip western part of the reservoir, grading downdip to less radiogenic waters (as low as 0.708903) to the east. Salinity (2800–50,000 mg/L) displays a parallel trend; saline waters to the west pass downdip to brackish waters. Elemental and isotopic data indicate that the waters originated as meteoric precipitation and acquired their salinity and radiogenic 87Sr through dissolution of Upper Permian evaporites. These meteoric-derived waters descended, perhaps along deeply penetrating faults, driven by gravity and density, to depths of more than 7000 ft (2100 m). The 87Sr/86Sr and salinity trends record influx of these waters along the western field margin and downdip flow across the field, consistent with the strong water drive, potentiometric gradient, and tilted gas-oil-water contacts. The formation water 87Sr/86Sr composition can be useful to evaluate subsurface flow and reservoir behavior, especially in immature fields with scarce pressure and production data. In mature reservoirs, Sr isotopes can be used to differentiate original formation water from injected water for waterflood surveillance. Strontium isotopes thus provide a valuable tool for both static and dynamic reservoir characterization in conjunction with conventional studies using seismic, log, core, engineering, and production data. Roger Barnaby has conducted stratigraphic studies of carbonates and siliciclastics in outcrop and subsurface for 15 years. He holds a Ph.D. from Virginia Polytechnic Institute and a B.S. degree from East Carolina University. Barnaby has worked on sedimentary successions of the Gulf Coast, Permian basin, Alaska North Slope, Middle East, and Caspian region. He maintains interests in carbonate diagenesis and geochemistry.Gregg Oetting received an M.A. degree in geology in 1995 from the University of Texas at Austin. He is the author of six publications concerning geochemical and strontium isotopic variations in Edwards aquifer groundwaters. For the past seven years, Oetting has traded energy futures for leading merchant energy concerns. He works for an independent consulting business in Houston, Texas. Guoqiu Gao received his B.S and M.S. degrees in geology from Central-South University, Hunan, China, and his Ph.D. in geology from the University of Texas at Austin. He works for a major oil company in Houston, Texas. His current interests lie in the field of geoscience computing.

Description: The Fruitland Formation of the San Juan basin is the largest producer of coalbed methane in the world. Production patterns vary from one well to another throughout the basin, reflecting factors such as coal thickness and fracture and cleat density. In this study, we integrated conventional P-wave three-dimensional (3-D) seismic and well data to investigate geological controls on production from a thick, continuous coal seam in the lower part of the Fruitland Formation. Our objective was to show the potential of using 3-D seismic data to predict coal thickness, as well as the distribution and orientation of subtle structures that may be associated with enhanced permeability zones. To do this, we first derived a seismic attribute-based model that predicts coal thickness. We then used curvature attributes derived from seismic horizons to detect subtle structural features that might be associated with zones of enhanced permeability. Production data show that the best producing wells are associated with seismically definable structural features and thick coal. Although other factors (e.g., completion practices and coal type) affect coalbed methane production, our results suggest that conventional 3-D seismic data, integrated with wire-line logs and production data, are useful for characterizing coalbed methane reservoirs. Iván Dimitri Marroquín is a Ph.D. student of geophysics at McGill University, Canada. He received his B.Sc. combined degree in physics and geology from the Université de Montréal in 1994 and his M.Sc. degree in geophysics from École Polytechnique in 1998. His current research includes characterization of conglomerate and coalbed reservoirs by 3-D seismic-based means.Bruce Hart holds a Ph.D from the University of Western Ontario. He held positions with the Geological Survey of Canada, Penn State, and the New Mexico Bureau of Mines and Mineral Resources prior to joining McGill University in 2000. His research interests focus on the integration of 3-D seismic data with other data types for reservoir characterization programs. He has been an associate editor of the AAPG Bulletin since 2000.

Description: A plot of fault throw vs. depth is a simple geometric tool that graphically represents strata thickness variations in growth-fault and growth-fold settings and has previously been used to infer fault kinematics. In this paper, we use it as a prediction tool for lithological change employing only seismic data. If growth faulting is a continuous process, intervals of shale deposition are recorded by unthickened units, while intervals of sand fill in topographic lows. The throw vs. depth plot easily allows depiction of unthickened and thickened sedimentary intervals from even rough seismic records and can therefore be used to predict sand/shale ratios. The method is here applied to a growth fault in the Niger Delta that affects Oligocene to lower Miocene deltaic deposits. Most shale intervals are identified, and the sand/shale ratios are predicted. We suggest that the method can be a valuable tool in oil exploration. Stéphane Pochat completed his Ph.D. in sedimentology and structural geology in June 2003 at Rennes University. He addressed the kinematics of growth faults with examples in deep-water turbiditic environments and their influences on sedimentary processes and made paleoclimatic reconstructions based on lacustrine sedimentology of Permian lakes. He is currently doing postdoctoral studies in the Laboratoire Régional des Ponts et Chaussées Institute (Lyon, France) on risks assessment.Sébastien Castelltort completed his Ph.D. in June 2003 at Rennes University. He worked on the origin of high-frequency terrigenous stratigraphic cycles, their relationships with growth folds and faults, and the numerical modeling of fluvial systems. He is now doing postdoctoral studies in the Earth Surface Processes Group at Eingeidnössische Technische Hochschule Zurich (Switzerland), working on the organization of drainage networks in mountain ranges. Jean Van Den Driessche has a Ph.D. from Montpellier University and completed a State thesis at Paris 7 University in 1994. He then worked on fault-sealing mechanisms in Elf Aquitaine, and since 1996, he has been a professor at the University of Rennes. His teaching and research work concerns tectonics, structural geology, and geomorphology. He has been chief editor of Geodinamica Acta since 1999. Katia Besnard works on the numerical modeling of water flows and reactive transport in heterogeneous porous media to understand the factors and processes influencing contaminants transport in groundwater flows. She also worked on the physical and numerical modeling of tectonic and sedimentation relationships. She completed her Ph.D. thesis in December 2003 at Rennes University, where she now does postdoctoral studies. Charles Gumiaux is a structural geologist with particular interests in the application of geostatistics. He worked on three-dimensional lithospheric deformation modeling of the Hercynian domain in Brittany (France) based on tomographic, magnetic, and seismic data analysis. He completed his Ph.D. in April 2003 at Rennes University and is currently doing postdoctoral studies at the Vrije Universiteit, Department of Tectonics (Amsterdam, Netherlands).

Description: Lower Cretaceous synrift lacustrine shales from the Congo Basin, west Africa, have been analyzed with sedimentological and geochemical techniques to characterize source rock quality and identify triggers for deposition of intervals richest in organic carbon. The sequence includes a lower active rift section, deposited during active faulting and subsidence, overlain by an upper late rift section, deposited during reduced faulting and subsidence. Total organic carbon (TOC) averages 2–3 wt.% throughout the active rift siliciclastic shale section, 6% in marls in the lower part of the late rift section, and 1–2% in deltaic shales in the upper part of the late rift section. Organic matter consists of mixed types I and III kerogen in the active rift shales, pure type I kerogen in the late rift marls, and a type I and III mixture in the late rift deltaic shales. Redox proxies indicate that the deep lake was relatively reducing throughout deposition of the active rift and lower late rift sections. Therefore, enhanced anoxia did not trigger deposition of the richest source rocks. Decreased sedimentation rates in the late rift do not account for the full increase in TOC nor the shift on organic matter type. The richest source rocks are associated with high rates of organic productivity and chemical sedimentation, indicating that flux of dissolved components to the rift lake, including nutrients for algae growth, was critical. We propose that reduced topography associated with the late rift was necessary for efficient cycling of plant-derived carbon into soil carbonate and ultimately the rift lake, and for enhancing chemical weathering and nutrient flux. Nick Harris has been a senior scientist in the Department of Geosciences at Pennsylvania State University since 1994. He previously worked as a research and exploration geologist for Conoco. He received his B.A. degree from Amherst College and his M.S. degree and his Ph.D. from Stanford University. His research focuses on source rocks, diagenesis, and the geology of the west African margin.Katherine H. Freeman is a professor in the Department of Geosciences at Pennsylvania State University, where she has taught since 1991. She received her B.A. degree from Wellesley College and her M.S. degree and her Ph.D. from Indiana University. Her research interests include molecular and isotopic indicators of biogeochemical processes and analytical methods in organic and isotope geochemistry. Richard D. Pancost is a lecturer in the Biogeochemistry Research Centre (Organic Geochemistry Unit) of the School of Chemistry, University of Bristol. He received his B.S. degree (1992) from Case Western Reserve University and his Ph.D. (1998) from Pennsylvania State University. His research interests include studies of organic matter preservation and the use of biomarkers in paleoclimate studies and geomicrobiology. Tim White is a research geologist with the U.S. Geological Survey and an adjunct research associate in the Earth and Mineral Sciences Environment Institute at Pennsylvania State University. He received his B.A. degree from Washington and Lee University and his M.S. degree and his Ph.D. from Pennsylvania State University. His research interests include paleoclimatology, paleopedology, chemostratigraphy, and organic petrology. Gareth D. Mitchell is a research associate and director of the Coal & Organic Petrology Laboratories, the Energy Institute, at Pennsylvania State University. He holds two degrees in geology, a B.S. degree (1974) from the Southern Illinois University and an M.S. degree (1977) from Pennsylvania State University. Prior to working at Pennsylvania State University in 1986, he was employed as a research engineer by Bethlehem Steel Corporation.

Description: Sierra de Hualfín is a 22-km (14-mi)-long basement-cored uplift with an approximately 66-km 2 (26-mi 2) exposure of the basement-cover interface. The uplift is composed of Ordovician granite, overlain by and locally thrust over Tertiary sedimentary rocks. The geometry of the uplift is that of a faulted anticlinorium in granite basement that is delineated by the basement unconformity. Detailed mapping of the basement unconformity documents large-scale folding of granite basement, the result of fault-propagation folding associated with a thrust-fault tip initially located deep in the basement. Our findings at Sierra de Hualfín indicate that homogeneous granite can fold as a deformable body by stress-induced development and/or exploitation of joints, faults and fractures, and an unconformity-parallel fracture foliation in the uppermost basement. Specifically, folding is achieved through systematic coordinated movements involving (1) reactivation of joints as faults and mode I fissures, (2) fracturing and faulting near large displacement faults, and (3) flexural shear of the uppermost basement. The extent to which joints, microfractures, and fracture foliation are reactivated determines the deformability of granite. At Sierra de Hualfín, the deformability of granite is such that the folding of the basement is consistent with trishear kinematics. Our observations contradict standard models of basement-cored uplifts that assume that the fault tip is located at the basement-cover interface. We postulate that the folded shape of Sierra de Hualfín and of some uplifts in the Rocky Mountain foreland can be attributed to basement distortion taking place in advance of a propagating fault tip below the basement-cover unconformity. Pilar García received her B.S. degree from Stanford University in 1995 and her Ph.D. from the University of Arizona in 2001. Her Ph.D. work focused on outcrop to regional-scale structural geology and tectonics of Sierras Pampeanas foreland uplifts. Now at ChevronTexaco, her work involves regional structural analysis of extensional regions, including western Africa, Brazil, and the Gulf of Thailand.George Davis received his Ph.D. from the University of Michigan (1971). He joined the faculty of the Department of Geosciences, University of Arizona (UA), in 1970, where he is now regents professor. His research has focused primarily on metamorphic core complexes and detachment faulting and Colorado Plateau structure tectonics. Currently, he serves as UA's executive vice president and provost.

Description: Coalbed gas content and composition are critical for the successful exploration and production of coalbed methane. We investigated the differential transport of a preadsorbed CO2-CH4 gas mixture along a coalbed aquifer by groundwater flow or across a coal bed by upward diffusion through pore water. Consistent analytical approximations and numerical solutions were obtained for typical cases. The results suggest that differential transport of CH4 and CO2 in a water-saturated coal seam is mainly controlled by their adsorption equilibrium in coals and solubilities in water. Although CO2 is about 20 times more soluble than CH4 in water at temperatures lower than 50°C, the transport of CO2 from a coal seam is only several times more efficient than that of CH4 because of the stronger adsorption of CO2 than CH4 in coals. Preferential transport of CO2 over CH4 by groundwater advection can substantially accumulate more gas rich in CO2 at downstream or near discharge zones if gas-trapping structures exist, and it may cause low total gas content of CH4 near recharge zones, which may explain the CO2 and CH4 distribution in the San Juan and Powder River basins and the undersaturation of gas in many other coals. The separation and redistribution of coalbed gas by transport processes may also be complicated by late-stage biogenic gas generation with infiltration of meteoric water with nutrients and gas-producing microbes into the coal beds as suggested for some basins. Overall, hydrogeologic systems strongly influence the distribution of coalbed gas content and composition in coal seams. Xiaojun Cui received a B.S. degree in geology from China University of Geosciences, Wuhan, an M.S. degree in geodynamics from Beijing University, and a Ph.D. in geological sciences from the University of Missouri, Columbia. Currently a postdoctoral fellow at the University of British Columbia, his research applies computer modeling to fluid flow in various geological systems.R. Marc Bustin is a professor of petroleum and coal geology in the Department of Earth & Ocean Sciences at the University of British Columbia, president of R. Marc Bustin Earth Science Consultants, and a principal of Coalbed Methane Solutions Ltd. Bustin's professional experience includes employment by Mobil Oil Canada, Gulf Canada Resources, Elf-Aquitaine (France), the Commonwealth Scientific and Industrial Research Organization (France), and the Centre National de la Recherche Scientifique (Australia). Bustin's research and consultancy is in the area of unconventional gas reservoirs, gas shales, and coalbed methane. Greg Dipple is a geochemist and an associate professor at the University of British Columbia with research interests in reaction and transport during water-rock interactions and CO2 sequestration.

Description: Triassic strata of the northern part of the Arabian plate mark the establishment of the Neo-Tethys passive margin. This ocean first opened in the western part of the Mediterranean region directly after the Hercynian orogeny. The strata were deposited on a shallow carbonate platform surrounded by clastic-evaporitic lagoons and continental fluvial and eolian settings. The rocks are divided between continental clastics (such as the Budra and the Ga'ara formations), continental-marine clastics and evaporites (such as the Mohilla, Abu Ruweis, Beduh, and Baluti formations) and epicontinental marine facies (such as the Saharonim, Salit, and Kurra Chine formations). These settings are comparable to those of the German Triassic and have matching lithofacies and eustatic sea level changes. The succession has been divided into four “high-frequency” sequences dominated by highstand systems tract carbonates and highstand systems tract–lowstand systems tract evaporites and clastics: the Mulussa Formation, the Kurra Chine dolomite and oolitic limestones, the clastics in the Euphrates–Anah graben in Syria and Iraq, and the Triassic buildups in the northern parts of the Levant form attractive hydrocarbon reservoirs when they are overlain by the Triassic–Jurassic evaporite sequence and are in communication with Silurian source rocks. In Syria, the Kurrachine Formation contains both source and reservoir rocks. On the Aleppo plateau, this formation is believed to lie at the beginning of the thermal maturation window, whereas in the areas of Jebbissa, Soukhne, and Souedie, it is in the mature or overmature windows. The Triassic strata produced fair amounts of light oil, gas, and condensates from some fields in Syria and Iraq with a high potential of gas and condensate accumulations in the Levant region. F. N. Sadooni has been an associate professor and chairman of the Department of Geology, United Arab Emirates University, since September 2001. He received a Ph.D. in petroleum geology from the University of Bristol, United Kingdom, in 1978. After working with Iraq National Oil Company as a senior exploration geologist for 13 years, Fadhil joined Yarmouk University, Jordan, in 1991 and then worked as a consultant petroleum geologist in Auckland, New Zealand. In 1998, he joined the University of Qatar as assistant professor before moving to the United Arab Emirates University. His research interests include carbonate reservoir characterization and evaporites. He is a member of the AAPG.A. S. Alsharhan is professor of geology at the United Arab Emirates University. He received a Ph.D. in petroleum geology from the University of South Carolina in 1985. He has authored and published more than 80 scientific papers. He coauthored Sedimentary basins and petroleum geology of the Middle East (1997) with A. E. Nairn and Hydrogeology of an arid region: Arabian Gulf and adjacent areas (2001) with Z. Rizk, A. E. Nairn, D. Bakhit, and S. Al-Hajari. He coedited Quaternary deserts and climate change (1998) with K. W. Glennie, G. Whittle, and C. Kendall and Middle East models of Jurassic / Cretaceous carbonate systems (2000) with R. W. Scott. His research interests include Holocene coastal sabkhas of the Arabian Gulf region and the geology and hydrocarbon habitats of the Middle East and North Africa. He is a member of the AAPG, SEPM, the International Association of Sedimentologists, and the Geological Society of London.

Description: Halokinetic and slope-instability processes have sculpted numerous morphological features on the flanks of the intraslope basins in the Bryant Canyon area. High-resolution geophysical data and long sediment cores (as much as 20 m [66 ft] long) were used to define the time and spatial evolution of sediment failures and their relationship to halokinetic processes. Two episodes of increased salt-tectonic activity are defined: (1) The first acted at the beginning of interglacial oxygen isotope stage 5 as salt adjusted to the abandoned environments of the Bryant and Eastern Canyon systems, and (2) the second occurred during the last glacial period and is characterized by the seaward propagation of salt masses. Three types of slopes are recognized in the intraslope basins: (1) highly inclined slopes with low-relief morphologic features resulting from shallow, translational slump complexes, (2) highly inclined slopes with high-relief morphologic features resulting from deep, rotational slump complexes, and (3) highly inclined slopes dissected by high-relief canyonlike landslide troughs resulting from channelized rotational slumps. The first two slope types occur mainly on the northern flanks of the basins, whereas the third type occurs on the southern flanks. We propose that the slump complexes on types 1 and 2 slopes were triggered by the oversteepening of the flanks by the seaward mobilization of underlying salt masses. The channelized rotational slumps on type 3 slopes are interpreted to result from the development of salt diapir bulges that lead to locally increased gradients on the basin flanks. Most of the sediment failures have been transformed into debris flows and led to the most recent phase of infilling of the basin floors. Efthymios Tripsanas is currently working as a postdoc at Bedford Institute of Oceanography in Dartmouth, Nova Scotia, with David Piper, Dave Mosher, and Kimberley Jenner. He is originally from Delphi, Greece, where he received his bachelor's degree in geology. He obtained his Ph.D. at Texas A&M University, College Station, Texas, with William Bryant. Efthymios has worked on sediment facies and slope instability associated with active salt tectonics on the Gulf of Mexico slope. His current research is focused on the understanding of sediment instability on the continental margin east of Newfoundland, particularly Orphan basin.William Bryant is a professor of oceanography. He received an M.S. degree and a Ph.D. at the University of Chicago. He has spent the last 40 years at TAMU teaching and doing research in marine geology, high-resolution marine geophysics, and marine geotechnology. He was head of the Department of Oceanography from 1998 to 2000. He has worked in the Gulf of Mexico, Caribbean, west Africa, the Arctic and Antarctic, and sailed all five of the Russian polar seas. He is the author of more than 300 papers, co-editor of 1 book, and advisor of more than 100 M.S. and Ph.D. graduates. He was co-chief scientist on Deep-Sea Drilling Program Leg 10, and scientist on Leg 96 and Oil Drilling Program Legs 113 and 121. Brett Phaneuf is a graduate student in the Department of Oceanography. His research focuses primarily on high-resolution applications to deep-sea imaging. Phaneuf works extensively with the U.S. Navy, particularly aboard the U.S. Nuclear Research Submarine, NR-1 , and also has been working with the Deep-Tow Research Group at Texas A&M for eight years.

Description: Triassic strata of the northern part of the Arabian plate mark the establishment of the Neo-Tethys passive margin. This ocean first opened in the western part of the Mediterranean region directly after the Hercynian orogeny. The strata were deposited on a shallow carbonate platform surrounded by clastic-evaporitic lagoons and continental fluvial and eolian settings. The rocks are divided between continental clastics (such as the Budra and the Ga'ara formations), continental-marine clastics and evaporites (such as the Mohilla, Abu Ruweis, Beduh, and Baluti formations) and epicontinental marine facies (such as the Saharonim, Salit, and Kurra Chine formations). These settings are comparable to those of the German Triassic and have matching lithofacies and eustatic sea level changes. The succession has been divided into four “high-frequency” sequences dominated by highstand systems tract carbonates and highstand systems tract–lowstand systems tract evaporites and clastics: the Mulussa Formation, the Kurra Chine dolomite and oolitic limestones, the clastics in the Euphrates–Anah graben in Syria and Iraq, and the Triassic buildups in the northern parts of the Levant form attractive hydrocarbon reservoirs when they are overlain by the Triassic–Jurassic evaporite sequence and are in communication with Silurian source rocks. In Syria, the Kurrachine Formation contains both source and reservoir rocks. On the Aleppo plateau, this formation is believed to lie at the beginning of the thermal maturation window, whereas in the areas of Jebbissa, Soukhne, and Souedie, it is in the mature or overmature windows. The Triassic strata produced fair amounts of light oil, gas, and condensates from some fields in Syria and Iraq with a high potential of gas and condensate accumulations in the Levant region. F. N. Sadooni has been an associate professor and chairman of the Department of Geology, United Arab Emirates University, since September 2001. He received a Ph.D. in petroleum geology from the University of Bristol, United Kingdom, in 1978. After working with Iraq National Oil Company as a senior exploration geologist for 13 years, Fadhil joined Yarmouk University, Jordan, in 1991 and then worked as a consultant petroleum geologist in Auckland, New Zealand. In 1998, he joined the University of Qatar as assistant professor before moving to the United Arab Emirates University. His research interests include carbonate reservoir characterization and evaporites. He is a member of the AAPG.A. S. Alsharhan is professor of geology at the United Arab Emirates University. He received a Ph.D. in petroleum geology from the University of South Carolina in 1985. He has authored and published more than 80 scientific papers. He coauthored Sedimentary basins and petroleum geology of the Middle East (1997) with A. E. Nairn and Hydrogeology of an arid region: Arabian Gulf and adjacent areas (2001) with Z. Rizk, A. E. Nairn, D. Bakhit, and S. Al-Hajari. He coedited Quaternary deserts and climate change (1998) with K. W. Glennie, G. Whittle, and C. Kendall and Middle East models of Jurassic / Cretaceous carbonate systems (2000) with R. W. Scott. His research interests include Holocene coastal sabkhas of the Arabian Gulf region and the geology and hydrocarbon habitats of the Middle East and North Africa. He is a member of the AAPG, SEPM, the International Association of Sedimentologists, and the Geological Society of London.

Description: Building stochastic models in a preproduction phase of field development is crucial for accurate horizontal well positioning in the Sincor field (Orinoco heavy-oil belt, Venezuela), formed by highly permeable unconsolidated fluvial and deltaic sands of the Oficina Formation and containing low-gravity oil (average 8.3° API). A multidisciplinary approach to drill the initial approximately 250 horizontal production wells has proven useful to field management. Geomodeling is used to evaluate well pattern development plans; calculate full-field production percentile profiles; and evaluate uncertainties in water production, well production potential, and cluster performance. Data from vertical observation wells (full well-logging suite) and deviated wells (to investigate the stratigraphy away from the vertical well) are used to characterize reservoir architecture. Three-dimensional seismic data, including seismic data inverted into acoustic impedance, are used to construct structure maps and shale probability maps. The integrated and interpreted information is used to position horizontal wells deterministically in a cluster-type (group of wells radiating out from a central point in a 3.2 × 1.6-km [2 × 1-mi] production area) development pattern and serves as input to stochastic reservoir models that are conditioned to vertical well observations and the shale probability maps. Ten realizations are used to estimate the uncertainty range of net-to-gross in the proposed horizontal well trajectories. To ensure a stable model, the average of these 10 realizations is used as a trend to generate one stochastic petrophysical model that is subsequently used for flow simulation. Based on the results, and in combination with the confidence in the interpreted geological data (for example, distribution of areas with a net sand thickness above a minimum), proposed horizontal wells are accepted or rejected. Tarald Svanes is discipline leader in subsurface uncertainty treatment at Statoil. Since 1990, he has worked with integrated, three-dimensional reservoir modeling and flow simulation, applying advanced geostatistical techniques. Currently, one of his main focuses is to reduce uncertainty in field prognoses by integrating production data into the reservoir characterization process. Svanes holds an M.S. degree in physics from the Norwegian Technical Institute in Trondheim. At Statoil, he has worked with various aspects of reservoir technology, ranging from research to operational field management, both in the North Sea and internationally.Allard W. Martinius has an M.Sc. degree from the University of Utrecht and a Ph.D. from Delft University. He joined Statoil in 1996 and spent his first three years at the research center in Trondheim, working on reservoir characterization and modeling of heterolithic tidal res ervoirs. He subsequently joined Sincor in Venezuela as a field development geologist. He returned to Statoil's research center in 2002 to lead a reservoir and uncertainty modeling research group. His main interests are in siliciclastic sedimentology, stratigraphy, reservoir characterization, and geomodeling. JoAnn Hegre received an M.Sc. degree from Tulane University (U.S.A.). She is currently head of geological research at Total's Geoscience Research Center in London. She has specialized in the field of geomodeling and reservoir characterization for the past seven years. Before taking up this position, she spent three years at Sincor, where she was in charge of geomodeling and volume calculations. Jean-Pierre Maret joined Total in 1982 and worked as field geologist and team leader at the head office in Paris until 1993. During that period, he spent two years in Abu Dhabi and four years in Buenos Aires. Subsequently, he became exploration manager for Total Myanmar in Yangon, where he spent four years; after which, he was in charge of field evaluation studies and exploration coordinator for southeast Asia. Recently, he worked for two years in Venezuela on the Sincor field, where he was responsible for the geology and geophysics studies and operations. Maret is currently the coordinator for the Americas for Total. Rune Mjøs is lead geologist for the Snorre field, northern North Sea, which he joined in 2002. Prior to that, he was seconded to the Sincor field in Venezuela as senior sedimentologist in the full-field evaluation team. He has been with Statoil since 1991 and has worked as exploration and production geologist on various technical evaluation projects. His main interest is in sedimentology and genetic stratigraphy. From 1997 to 1999, he was Statoil's advisor in sedimentology. Rune has a Cand. Scient. degree from the University of Bergen. After obtaining his degree, he worked for two years as exploration geologist for Norsk Hydro and subsequently, four years as scientist at Rogaland Research Institute. He has published articles on sedimentology, diagenesis, and sequence stratigraphy both for petroleum exploration and production purposes. Juan Carlos Ustáriz Molina, a petroleum engineer from the Universidad Central de Venezuela, obtained his degree in 1994. Since then, he has worked for Mares de Venezuela (MARAVEN) and Petróleos de Venezuela S. A. (PDVSA) in operations and reservoir simulation. In 1998, he started to work for Pennzoil in western Venezuela as a geomodeler and joined Sincrudos de Oriente (SINCOR) as geomodeler in 2000.

Description: Petrographic observations indicate that the distribution of cement and porosity within a Quaternary-age thrust fault in the subsurface of the Wheeler Ridge oil field in California is a function of depth and temperature and varies spatially. At depths shallower than 2.5 km (1.6 mi), porosity increases because of the abundance of open microfractures and plagioclase dissolution. At depths greater than 2.5 km (1.6 mi), the porosity in the fault zone decreases because of calcite cementation in microfractures that ultimately form vein networks. Based on δ18O data, we distinguished veins cemented by intraformational (lateral) flow into the fault from veins cemented by ascending fluids along the fault. Ascending, cementing fluids traveled at least 75–750 m (246–2460 ft) vertically. The petrography suggests that oil migration was the last event following dissolution and calcite cementation in the fault zone. Based on oil chemistry, whole-oil δ13C, API gravity, and petrographic data, we propose that hydrocarbons, presently in shallow and deep reservoirs, flowed laterally into the fault zone. Whereas hydrocarbons in shallow reservoirs flowed across the fault into the hanging wall, hydrocarbons in deep reservoirs were trapped against the fault in the footwall. The increase of API gravity with depth and lack of evidence for retrograde condensation indicate a limited vertical migration and reaccumulation of hydrocarbon, suggesting that below 2.5 km (1.6 mi), the thrust behaves as a vertical seal. The sealing properties of the thrust vary spatially and may be controlled by calcite cementation.

Description: The external and internal geometry of four turbidite systems outcropping around the Buil syncline (Ainsa basin, Spanish Pyrenees) has been reconstructed with reservoir-scale resolution in three dimensions (3-D). The irregular geometry of the syncline and the resolution required for the reconstruction cannot be resolved with cross sections. Therefore, reconstruction has been carried out with a new methodology that applies a 3-D dip-domain geometrical model and 3-D restoration techniques to achieve reservoir-scale resolution in kilometric-scale reconstructions. This methodology is aimed at resolving 3-D geometries in folded areas and regions with variable thickness stratigraphy. The 3-D reconstruction of the Buil syncline reveals the synsedimentary growth of an intrabasinal anticline and the foreland lithospheric flexure associated with tectonic loading north of the Ainsa basin. Oscar Fernández received his degree in geology in 1999 from the Universitat de Barcelona. Since then, he has been carrying out research as a structural geologist in the Geodynamics and Basin Analysis Group (Universitat de Barcelona). His research is focused on 3-D structural reconstruction methodologies.Josep Anton Muñoz is professor of structural geology at the Universitat de Barcelona. He received his Ph.D. in 1985 from the Universitat de Barcelona and worked for the Servei Geològic de Catalunya from 1985 to 1990, when he joined the Universitat de Barcelona. His research interests include the structure of thrust and fold belts, tectonosedimentary relationships, and tectonics of collisional orogens. He is currently focusing on the construction of 3-D structural models. Pau Arbués received his degree in geology in 1987 from the Universitat Autònoma de Barcelona. He has worked as an independent consultant for 11 years, contracting research for the Servei Geològic de Catalunya and various oil companies. For the last 5 years, he has been working as a researcher in sedimentology for the Geodynamics and Basin Analysis Group (Universitat de Barcelona). Oriol Falivene received his degree in geology in 2002 from the Universitat de Barcelona. He works as a researcher in reservoir modeling and sedimentology for the Geodynamics and Basin Analysis Group (Universitat de Barcelona). His areas of interest include turbidite and alluvial fan reservoir analogs. A professor of stratigraphy at the Universitat de Barcelona, M. Marzo's research interests focus on the application of clastic sedimentology, sequence stratigraphy, reservoir modeling, and basin analysis to the exploration and production of hydrocarbons. He has been involved in several research projects funded by oil companies in southern Europe, North Sea, South America, and northern Africa.

Description: Geochemical and isotopic data indicate the presence of CO2 of both organic and inorganic origin in the natural gas reservoirs of the Yinggehai Basin. The natural gases with inorganic CO2 commonly show a high content of CO2, ranging from 15 to 85%; a heavier carbon isotope value of CO2, from -0.56 to -8.16‰; and a lower 3He/4He ratio, ranging from 0.20 to 6.79 × 10-7, indicating a crustal origin. These gases occur locally, commonly related to diapir structures. Natural gases rich in hydrocarbons occur widely and are characterized by a low CO2 content, from 0.1 to 5.0%, and a lighter C1 carbon isotope value from -10.59 to -20.7‰, indicating an organic origin. Geological background and geochemical data indicate that the Sanya and Meishan formations are the main source of hydrocarbon gases and the organic CO2. Pyrolysis experiments on Tertiary calcareous shales and thermal history modeling both suggest that the calcareous shales occurring in the lower Miocene strata are the main source of the inorganic CO2 gas, whereas thermal contact metamorphism of the Paleozoic carbonates and/or magmatic CO2 may have made only a small contribution. Abnormally high paleogeothermal gradients (4.25–4.56°C/100 m; 12.09–12.26°F/100 ft) and a rapid heating rate caused the lower Miocene calcareous shales to reach the threshold temperature (about 300°C [570°F]) of their thermal decomposition at the burial depth of about 6500 m (21,300 ft) and to generate great volumes of inorganic CO2 gas. Diapir faults acted as the main pathways for the upward migration of deep inorganic CO2 gases into reservoirs connected with shale diapirism along the central Yinggehai Basin. The heavier carbon isotope values of associated methanes and a strong thermal anomaly in the CO2-rich gas reservoirs provide evidence that the inorganic CO2 gas migrated into the reservoirs later than their associated hydrocarbon-rich gases. This suggests that the earlier formed traps and sandstone reservoirs distant from shale diapir structures may have greater potential in the exploration for hydrocarbon-rich gases.

Description: There are two significant challenges in building a reservoir model integrating all available information. One challenge is that wells and seismic data measure the reservoir at different scales of resolution. The other challenge lies in how to account for conceptual geological knowledge with resolution at multiple scales. In this paper, we present a case study of integrating well data, seismic data, and conceptual geologic models. The well and seismic data are of good quality, but conventional well-seismic data calibration indicates that the seismic data are unable to fully differentiate sand from shale. The reason for this poor well-seismic data calibration is that well log and seismic data measure the reservoir at different scales. Well logs are able to differentiate sand from shale, whereas seismic data are better at detecting larger scale depositional geometries. A new workflow is presented to deal with this problem. First, principal component analysis clustering is used to identify characteristic patterns of certain depositional facies, from which sandy and shaly channels are interpreted. Next, multiple-point geostatistical simulation is performed to build a depositional-facies model, which integrates both hard and soft data but also incorporates realistic depositional-facies geometries provided by our geological knowledge of this reservoir. Finally, different lithofacies (sand and shale) indicators and corresponding petrophysical properties are simulated honoring the limited well data. The results show that not only are the geological features better reproduced, but also is the uncertainty about the reservoir significantly reduced because of a better integration of corresponding three-dimensional seismic data. Yuhong Liu holds a Ph.D. in geological and environmental science from Stanford University (2003). She worked at the University of Petroleum, China, as an assistant professor and a lecturer from 1995 to 1999, working on industry projects related to petroleum geology and reservoir characterization. She joined ExxonMobil in 2003 and now works on geological modeling and geostatistics as a research geologist.Andrew Harding holds an M.A. degree in physics from Trinity College, Cambridge, in Great Britain. He has worked in the oil industry since 1975, the last 23 years with ChevronTexaco. He presently is a consultant in reservoir modeling in San Ramon, California, and works on projects from around the world. Andrew is a chartered geologist of the Geological Society of London. William Abriel (Bill) received his B.S. and M.S. degrees in geophysics (1978) from Pennsylvania State University. Joining Chevron Oil Company from 1978 to the present, he has been involved in many interesting projects in both operations and seismic research offshore and onshore in North and South America, Europe, Asia, Australia, and Africa. Bill is a member of the Society of Exploration Geophysicists (SEG), European Association of Exploration Geophysicists, and AAPG and the 2004 SEG Spring distinguished lecturer. Sebastien Strebelle earned his Ph.D. at Stanford University in geological and environmental sciences in 2000. His research focuses on reservoir geomodeling and geostatistics. He is currently employed as a research geoscientist with ChevronTexaco.