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The south flank of the Uinta Basin in northeast Utah is the high Tavaputs Plateau that dips gently northward towards the basin center and is deeply dissected by the Green River and its tributaries. Where not removed by canyon incision, bitumen-impregnated sandstones in the Green River Formation (lower Eocene) occur along nearly the full length of the plateau. The bituminous sandstones encompass an area greater than 600 square miles and hold an estimated 11.6 to 14.0 billion barrels of bitumen, but the net thickness of bituminous sandstone and the OOIP rarely exceed 70 feet and 80 thousand barrels per acre (MBO/ac), respectively. However, in an exceptional 4.6 square mile area centered on Bruin Point (elev. 10,184 ft) on the southwest basin rim, the net thickness of bituminous sandstone and OOIP are measured in hundreds of feet and MBO/ac, respectively. The estimated bitumen in place in just this small area is 1.16 billion barrels. Bruin Point is an erosional remnant of a structural-stratigraphic trap formed by the superposition of a subtle flexure on a thick stack of deltaiclittoral sandstones. In the 1970s and 1980s, this unique area was extensively investigated to characterize the reservoirs and delineate the hydrocarbon resource. Over 117 test wells with cores were drilled and analyzed. As many as 32 stacked bituminous sandstone bodies were encountered, 15 of which hold nearly all the bitumen. The sandstones were deposited in constantly shifting deltaic lobes and along inter-delta shorelines. They are encased in marsh and floodplain mudstone and littoral-lacustrine calcareous mudstone and bioclastics. The sandstones are poorly sorted, fine-grained feldspathic arenites up to 115 ft thick in distributary channels, but less than 10 ft thick in beach deposits. Average porosity and permeability are 23% and 570 md, respectively, but values vary widely between, and even within, depositional settings. The bitumen at Bruin Point is heavy (8.6o API) and highly viscous (106 cP). Just 25 miles to the north, these same amalgamated deltaic sandstones are the reservoirs in the Greater Monument Butte conventional oil field. Although many operators have attempted to exploit the Bruin Point site for liquid hydrocarbons using both in situ steam flood and mining with solvent extraction, so far only small-scale mining of the bituminous sandstones for road construction has been commercially successful. This paper presents seven cores, several exceeding 1000 ft in length, that graphically display the distribution of bitumen resource as related to stratigraphic heterogeneity and location within the Bruin Point sector of the Sunnyside deposit.

Summary In recovery of heavy oil by steamflood, efficiencies can be realized by limiting the placement of steam to the portions of the reservoir with highest oil saturations, thus reducing the disproportionate loss of heat to connate water. This optimization strategy requires knowledge of water-saturation (Sw) distributions within the heavy-oil reservoir at the scale of operations. Application of this strategy has contributed to the successful reactivation of the shut-in Pru Fee property in the Midway-Sunset field 1 mile west of Taft, a U.S. Dept. of Energy (DOE) Class 3 oil-technology demonstration project. The 40 new wells drilled and logged within the 40-acre Pru Fee property, together with a single continuous core, have permitted 3D mapping of Sw within the 250- to 350-ft-thick pay zone in the Monarch sand reservoir. Water saturations are observed to vary at three different scales: A systematic vertical reduction in Sw through a 100- to 150-ft interval above the oil/water contact (OWC) caused by dominant capillary influence where the buoyancy effects are diminished by the low-density contrast of the 13°API oil and formation water. Lateral variations in Sw on the scale of 10 to 100 ft caused principally by prior oil production from the reservoir, but modified by its internal stratigraphic architecture. Bed-to-bed variations in Sw on the order of a few feet or less constrained by grain-size-controlled differences in porosity/ permeability in these crudely graded sands. Overall production efficiency in the steamflood has been improved by limiting steam injection to the upper one-half to two-thirds of the pay zone, where Sw is lowest. Knowledge of the lateral variations in Sw has permitted more accurate appraisal of the effectiveness of individual producers and nine-spot injector/ producer arrays. The recognition of the bed-to-bed variations has permitted a better petrophysical model for calibrating Sw calculated from logs.

The Uinta Basin in northeastern Utah is one of the principal petroleum provinces of the Rocky Mountains, and interest has been increasingly converging on its large deposits of unconventional hydrocarbon resources. Despite their apparent abundance and shallow depths, however, the bitumens, heavy and extra-heavy oils of the Uinta Basin have hitherto resisted commercial exploitation. They are immobile and technically stranded and will require innovative applications of in-situ thermal recovery methods for commercial production to proceed. Moreover, although some individual oil samples have been intensely investigated, a coherent literature on the physical and chemical properties of the Uinta Basin's unconventional oil resources is lacking. Nearly all of the exploration, laboratory research, and field trials on the Uinta Basin have concentrated on surface mining and retorting, producing a database that is heavily slanted toward mining methodologies. The occasional pilot studies of in-situ recovery have been very small and inconsequential. The information that does exist on Uinta's immobile oils is scattered across obscure in-house industry or government reports, unpublished core logs in public files at the Utah Geological Survey, and an array of academic articles. This chapter assembles data from published and unpublished sources to document the variations in the immobile reservoired oils from one part of the basin to another. The focus of this chapter is the geologic setting, the character of the sandstone reservoirs, the properties of the reservoired oils, and the size of the unconventional oil accumulations of the Uinta Basin. Immobile oils of the Uinta Basin can be subdivided into two main categories. The first is heavy oils and bitumens form the tar-sand deposits that rim the Uinta Basin and are known to occur in shallow parts of conventional oil fields in the basin's interior. They are immobile by virtue of their high viscosity related to oil composition, with 10 to 20 API for heavy oils and less than 10 API for bitumens. The second category is lighter oils with pour points in excess of the ambient reservoir temperature, rendering them immobile. These are found in shallow pools overlying several of the basin's conventional oil fields. Advances in in-situ technologies will be required to recover these currently technically stranded oils. Three distinct geologic settings for shallow immobile oil accumulations exist in the Uinta Basin. Along the basin's southern flank, oils within the lower members of the Green River Formation are reservoired in lenticular distributary channels and marginal lacustrine sandstones, forming the main reservoirs of the West and East Tavaputs plateaus. East of the Green River, the sandstones are relatively porous and permeable but tend to have both low oil saturations and highly variable oil impregnation, depressing the average volume of original oil in place (OOIP) per unit area (less than 30,000 bbl/ac) in the P.R. Spring–Hill Creek deposit. The Sunnyside deposit beneath the West Tavaputs Plateau is similar to the P.R. Spring–Hill Creek deposit in this respect, except in the small area of the Dry Creek Canyon–Bruin Point–Range Creek. Here stacked fluvial channels in the Douglas Creek Member locally hold as much as an order of magnitude more oil as the rest of the southern flank deposits. Throughout the southern flank, reservoired oils are asphaltene rich, saturate poor, and very viscous; they are either extra-heavy (bitumen) or heavy oils, averaging less than 10 API. Biomarkers indicate that they are immature Green River oils that have been heavily biodegraded. Along the northern margin of the Uinta Basin, heavy oil is reservoired in Mesozoic sandstones on the upturned hanging wall of the Uinta Basin boundary fault and in fluvial and marginal lacustrine sandstones of the late Eocene strata that unconformably onlap the thrust fault. Asphalt Ridge and Whiterocks are the only major heavy-oil deposits identified, but exploratory drilling in buried parts of the thrust sheet may reveal others. At Asphalt Ridge, the stacked fluvial channels of the Mesaverde Group contain 120 to 190 thousand bbl/ac of OOIP. The sole reservoir at Whiterocks, the eolian Nugget Sandstone (Triassic–Jurassic), is porous, moderately permeable, and relatively homogeneous. As the reservoir is subvertical, the height of the oil column, instead of the thickness of the reservoir, determines the OOIP, which is in the range of 450 to 485 thousand bbl/ac. The heavy oil in both deposits ranges between 10 and 14 API and has the composition of moderately biodegraded conventional Uinta Basin oil. Viscosities are considerably lower than those of the southern flank oils, and the oil is easily upgraded to marketable products. The shallower central parts of the Uinta Basin reservoir both moderately biodegraded heavy oil and normal oil with a pour point above ambient temperature in the lenticular fluvial channel upper Eocene sandstones. If the Wonsits Valley shallow oil pools are typical of similar accumulations in the central basin, biodegraded oils yield to normal immobile oils downsection and are replaced with normal mobile oils at current production depths below 1220 m (4000 ft). Emission of small amounts of biogenic gas from the shallow accumulations indicates active biodegradation of these immobile oils.

The Carboniferous-Lower Permian carbonate succession of the Timan-Pechora basin is a major hydrocarbonbearing complex, hosting about half of the oil and nearly a third of the gas reserves of the basin. The succession represents the last episode of carbonate deposition on the northeastern margin of the Russian platform before the closure of the Ural seaway in the mid- Permian. The lower part of the succession (upper Visean-Moscovian) contains three major transgressive-regressive sequences. Depositional facies ranged from nearshore carbonate-shale-evaporite through shallow shelf detrital carbonates to outer-shelf carbonate-siliceous shale. The most pronounced regression during this interval occurred during the Serpukhovian, when marine sabkhas covered vast portions of the carbonate platform. Late Carboniferous-Early Permian sedimentation was complicated by the onset of Uralian tectonism. Flysch from the encroaching orogen accumulated initially in the east, advanced westward across the passive margin, and fi...

The bulk of the hydrocarbon resources of the Timan-Pechora basin on the northeastern margin of the Russian platform is hosted in reservoirs and traps in the Middle Devonian-Triassic stratigraphic interval, the second of three Phanerozoic first-order cycles. The stratigraphic positions of source rocks, reservoirs, and seals within this important first-order cycle bear specific and predictable relationships to stages within second-order transgressive-regressive cycles. Anticlinal traps constitute 12-15% of the surface area of the basin and host about 75% of the discovered reserves. In addition, numerous styles of stratigraphic and combination traps are recognized. Understanding of the stratigraphy of the basin points to many additional reservoirs and trap styles that as yet are underexplored. The prospects for significant future discoveries of oil and gas in the Timan-Pechora basin are high.

A new geometric model for the Suez rift suggests that isostatic uplift of an underlying low-angle normal fault system accompanying early block faulting localized subsequent deep-seated extension. This, in turn, created a superimposed late-stage graben system offset to the east from an earlier locus of extension. Initial extension in the Oligocene and earliest Miocene drove minor rotation on wide tilt blocks over an eastward-dipping low-angle normal fault system and formed a series of wide half-grabens. With increasing extension, more closely spaced faults formed smaller rotating tilt blocks, fragmenting the larger, earlier half grabens and creating numerous sub-basins. In response to this brittle thinning of the upper crust, isostatic uplift of the lower crust arched the underlying low-angle fault surface, limiting gravity-driven tilt-block movement in the west by flattening the low-angle fault surface and creating a broad gulf-parallel high in the fault surface and Moho under the eastern portions of the rift. This process diminished faulting in the west and localized continuing deep-seated extension under the crest of the arch, possibly through induced mantle convection. Through-going faults thus initiated cut the old low-angle fault system and bound a system of down-dropped grabens offset to the east of the most extended portions of the older tilt-block array. In the Red Sea, immediately to the south, this process has continued, with the increased separation allowing the formation of mantle-derived oceanic crust. This model suggests that early movement over low-angle detachments and accompanying isostatic response may play an important role in localizing deformation within rifts, and are probably critical elements in the early formation of passive margins.

Thrustbelts are likely to be productive sources of hydrocarbons well into the future. Many new technical tools are enabling new discoveries, or the more efficient recovery of known reserves. The authors provide a comprehensive account of thrust systems, including orogenic thrustbelts, transpressional ranges and accretionary prisms and discuss both thin-skin thrust systems and thick-skin inversion structures. The book includes major sections on the basic concepts, definitions and mechanics of thrust systems, the roles of syn-tectonic stratigraphy and fluid flow in determining structural style, the origins and nature of evolving thermal regimes in thrustbelts, and a thorough analysis of petroleum systems and hydrocarbon plays in thrustbelts. Case studies are presented with discussion of the potential applications of the technique, possible limitations and future developments. A comprehensive database of thrustbelts is available to download. This book will be an invaluable resource for research scientists, oil company managers and students.

In recovery of heavy oil by steam flood’ efficiencies can be realized by limiting the placement of steam to portions of the reservoir with highest oil saturations, thus reducing the disproportionate loss of heat to connate water. This optimization strategy requires knowledge of water saturation (Sw) distributions within the heavy oil reservoir at the scale of operations. Application of this strategy has contributed to the successful reactivation of the shut-in Pru Fee property in the Midway-Sunset field one mile west of Taft, a DOE Class 3 oil technology demonstration project. The 40 new wells drilled and logged within the 40 acre Pre Fee property together with a single continuous core have permitted 3D mapping of Sw within the 250–350 ft thick pay zone in the Monarch Sand reservoir. Water saturations are observed to vary at three different scales: A systematic vertical reduction in Sw through a 100–150 ft interval above the OWC due to dominate capillary influence where the buoyancy effects are diminished by the low density contrast of the 13º API oil and formation water.Lateral variations in Sw on the scale of 10–100 ft due principally to prior oil production from the reservoir, but modified by its internal stratigraphic architecture.Bed-to-bed variations in Sw on the order of a few feet or less constrained by grain-size controlled differences in porosity-permeability in these crudely graded sands. Overall production efficiency in steam flood has been improved by limiting steam injection to the upper one-half to two-thirds of the pay zone, where Sw is lowest. Knowledge of the lateral variations in Sw has permitted more accurate appraisal of the effectiveness of individual producers and nine-spot injector-producer arrays. The recognition of the bed-to-bed variations has permitted a better petrophysical model for calibrating Sw calculated from logs.

The objective of the project is not just to commercially produce oil from the Pru Fee property, but rather to test which operational strategies best optimize total oil recovery at economically acceptable rates of production volumes and costs.

A previously idle portion of the Midway-Sunset field, Aera Energy's Pru Fee property, has been brought back into commercial production through tight integration of geologic characterization, geostatistical modeling, reservoir simulation, and petroleum engineering. This property, shut-in over a decade ago as economically marginal using conventional cyclic steaming methods, has a 200–300 foot thick oil column in the Monarch Sand. However, the sand lacks effective steam barriers and has a thick water-saturation zone above the oil-water contact. These factors require an innovative approach to steam flood production design that balances optimal total oil production against economically viable steam-oil ratios and production rates. The methods used in this DOE Class III oil technology demonstration are accessible to most operators in the Midway-Sunset field and could be used to revitalize properties with declining production of heavy oils throughout the region. The production strategy adopted in the steam flood pilot is to restrict steam injection to the upper one-third of the pay zone, that portion where oil saturations exceed 50%. Any steam injected below this interval would loose large quantities of heat to water and result in unfavorable steam-oil and water-oil ratios. During the fourth year of the oil demonstration project, production from the 8 ac four-pattern steam flood pilot continued to remain high. As of December 1999, the oil rate was averaging 308 BOPD and the cummulative oil production from the pilot alone was 335 MBO. The steam-oil and water-oil ratios, measures of steam flood effectiveness, closed the year at about 5 and 8, respectively. Also, an additional 37 new wells drilled in 1998 surrounding the pilot have been put into cyclic production. By the end of 1999 they were producing up to 458.3 BOPD, bringing the total oil rate for the Pru Fee property up to 689.0 BOPD. The total production from the property since the beginning of the project in late 1995 is 541.0 MBO. The average production rates per well are higher under steam flood than in cyclic mode.

During the initial phase of the project a multifaceted feasibility study was carried out to examine whether the pilot project could be justified technically and economically at this site. This study included: (1) Recompletion of 9 shut-in wells and drilling of a additional producer and a new temperature observation well. A core was taken from the reservoir interval in the new producer, Pru-101. The wells were produced by conventional cyclic steaming over a period of 15 months to establish a production baseline for the site, (2) Characterization of the stratigraphy and petrophysical properties of the Monarch Sand reservoir using existing well logs and analyses on samples in the core taken from Pru-101. The resulting data were used to develop a geostatistical model of the reservoir at the Pru Fee property and a specific reservoir simulator for the pilot test site on the property, and (3) Use of the reservoir simulator to test various steamflood and cyclic steaming production options leading to design of a production strategy for the pilot steamflood based on a four pattern, 9-spot array covering 8 ac near the center of the 40 ac Pru Fee property. The array chosen required drilling additional producers and injectors to supplement the existing wells recompleted in the initial phase of the project.

PRU Fee, an idle lease in the Midway Sunset Field has been a site of a U.S. DOE-sponsored Class III project. A geologic and stratigraphic model of the site was constructed using logs and core data. Geostatistical approach was used in generating reservoir images. Reservoir simulations were performed to study the effectiveness of various processes and to examine the sensitivity of parameters. The study showed that oil can be recovered economically from the lease using conventional steam flood technology provided the injectors are completed an optimum distance above the oil water contact. Simulations also showed that it was possible to recover additional oil by appropriately placing horizontal producers later in the life of the flood.

This project reactivates ARCO`s idle Pru Fee lease in the Midway- Sunset field, California and conducts a continuous steamflood enhanced oil recovery demonstration aided by an integration of modem reservoir characterization and simulation methods. Cyclic steaming is being used to reestablish baseline production within the reservoir characterization phase of the project. During the demonstration phase scheduled to begin in January 1997, a continuous steamflood enhanced oil recovery will be initiated to test the incremental value of this method as an alternative to cyclic steaming. Other economically marginal Class III reservoirs having similar producibility problems will benefit from insight gained in this project. The objectives of the project are: (1) to return the shut-in portion of the reservoir to optimal commercial production; (2) to accurately describe the reservoir and recovery process; and (3) to convey the details of this activity to the domestic petroleum industry, especially to other producers in California, through an aggressive technology transfer program.

Paleozoic to Oligocene metasedimentary rocks present in the Alpi Apuane region of the Northern Apennines, Italy, have been sequentially deformed during a Tertiary progressive deformation. In an attempt to date the individual deformation episodes, over 50 conventional K-Ar and 1140 Ar/39Ar incremental gas release analyses have been carried out on fine grained white micas separated from samples whose structural settings were well known. Mineralogy, X-ray diffractometry, and thin-section analyses indicate that the constituent muscovite and phengite formed under metamorphic conditions of 3–4 kbars and 300–400°C during all deformational phases. Pre-existing micas were variably crenulated during each subsequent deformational phase. Both K-Ar and 40Ar/39Ar analyses were carried out on 0.6-2μm, 2–6 μm and 6–20 μm size separates of the phengitic white mica. Although the K-Ar apparent ages range from 11 to 27 Ma and are consistent with available stratigraphic constraints, the 40Ar/39Ar age spectra display variable internal discordancy. These isotopic data indicate that: (1) both the K-Ar and 40Ar/39Ar total-gas ages decrease as the degree of crenulation increases; (2) the K-Ar and 40Ar/39Ar total-gas ages decrease as grain size decreases; (3) for each sample, characteristics of the 40Ar/39Ar age spectra depend upon grain size, with fine sizes yielding discordant patterns which systematically increase in apparent age from low to high temperature and (4) phengitic micas associated with earliest structures yield generally older ages than micas associated with later structures. The isotopic results are interpreted to indicate that the major deformation phase (D1) occurred at approximately 27 Ma with subsequent pulses ending by c. 10 Ma. These results may be combined with finite strain data to suggest that the region was deformed at strain rates between 10−15 and 10−14 s−1. A 27 Ma age indicates Mid-Oligocene initiation of plate tectonic activity in the Western Mediterranean and concomitant deformation in the Northern Apennines.

Djebel Debadib is a northeast trending anticline in the Tunisian Atlas, near El Kef, Tunisia. The core of the anticline consists of a deformed Triassic, gypsum-matrix breccia containing clasts of supratidal dolomite, terrigeneous clastic rocks, and ophites (metabasites). Locally, low-grade metasedimentary rocks, occurring as clasts in the evaporite, may represent fragments of basement rock plucked from salt subcrop during deep-seated flowage. The multiply deformed Triassic rocks are juxtaposed against Cretaceous or younger rocks, and Jurassic and Neocomian strata are not present in outcrop. These characteristics have been cited in many studies to suggest a history of diapirism to explain both the internal structure of the Triassic rocks and the contact relations with the younger rocks. A previously unreported unconformity, developed on the Triassic rocks and overlain by Aptian-Albian strata, indicates that an important period of piercement occurred during the Early Cretaceous for the Djebel Debadib diapir. From the mid-Cretaceous to the late Eocene the continental margin of northern Tunisia was a regional basin in which a thick sequence of carbonate rocks was deposited. Beginning in late Oligocene time, sandy clastic sediments accumulated on the older carbonate rocks above a regional unconformity, and during the middle Miocene Atlas orogeny, numerous northeast-southwest folds deformed the rocks of the Tunisian trough including the diapiric Triassic masses. These folds, commonly boxlike in geometry, were extensively faulted during the late Miocene and Pliocene. A four phase tectonic model is recognized for the Tunisian Atlas: (1) early Mesozoic rifting of the North African continental margin, (2) diapiric emplacement of the Late Triassic-Liassic(?) evaporites into overlying strata beginning in the early Cretaceous, (3) folding of the cover strata in response to regional compression culminating in the middle Miocene Atlas orogeny, (4) the development of transvers grabens during late orogenic normal faulting (latest Miocene to Recent). A major regional decollement is not considered necessary to account for the shortening of the sedimentary cover during the middle Miocene deformation. Rather, the principal driving mechanism of regional crustal shortening was the reactivation of early Mesozoic normal faults as reverse faults that displaced basement rocks. This model implies that the small amount of shortening recorded in the Tunisian Atlas involved active shortening and structural thickening of basement and the concurrent deformation of the sedimentary cover.

Hydrocarbon traps in the Gulf of Suez, whether of a structural or a stratigraphic type, fundamentally are all products of the highly complex late Cenozoic fault-block mosaic. Understanding the geometry and the evolution of this tilt-block mosaic is the key to further successful exploration in the Gulf. The major faults forming the Gulf of Suez basin are listric normal faults broken along strike by synchronous cross faults that serve as transform or "transfer" structural elements. The cross faults are a consequence of the inability to form uniform and laterally continuous listric fault surfaces within the mechanically anisotropic and inhomogeneous crystalline basement terrane of the Gulf. The combination of contemporaneous Gulf-parallel listric faults and cross-strike "transfer" faults gives rise to the complex mosaic of polygonal tilt blocks. Vertical variations in the structural behavior result from a synrift stratigraphy dominated by thick marls and evaporites. The ductile synrift rocks exhibit shallow secondary detachments, drape folds, and compaction and/or diapiric structures t at are decoupled from, but appear controlled by, the brittle underlying basement-rooted tilt-block mosaic. Lateral stratigraphic variability observed in the Gulf is the consequence of sea level rising and falling relative to the higher structural elements in the tilt-block mosaic. This has resulted in deeply eroded basement highs, clastic apron and perched reef reservoirs associated with the highs, and thick organic-rich marl accumulations in the intervening lows that serve as "kitchen" areas. End_of_Article - Last_Page 305

Detailed structural mapping in the southern Hedil region of the northern Tunisian Atlas suggests that the area is characterized by multiple-faulted folds, facing southeast, rather than by the nappes and imbricate thrusts of previous interpretations. Our structural analysis shows that major deformation occurred during the middle Miocene (Langhian-Serravallian). This deformation was progressive and occurred in two discrete phases. In the first phase, shelf-type rocks of Late Cretaceous-early Miocene age were involved in kink-style folding which developed above a gliding surface in Triassic evaporites to form northeast-trending structures. The second phase produced conjugate strike-slip and extensional faulting in these structures. The acute bisectrix of the strike-slip faults, at right angles to the major trends of folding and parallel with the extensional faults, suggests that the maximum principal compressive stress (^sgr1) was directed S38°E and was constant during middle Miocene deformation. This faulted-fold co cept contrasts with that suggested in other studies in which the sequence of events is envisioned as faulting followed by folding.

The stratigraphic evolution, structural styles, and principal hydrocarbon prospects of the Tunisia-Sicily shelf are all linked to the crustal "template" created during the middle Mesozoic rifting of the Tethyan margin of North Africa. Transtensional stretching and fragmentation of the Tunisia-Sicily shelf during the Late Triassic to Jurassic at the junction of the south Sahara and Gilbraltar fracture zones created a complex array of ridges and furrows and localized pull-apart basins. This block-faulted shelf region was buried during the Cretaceous and early Cenozoic beneath a cover stratigraphy that ranged widely from a thin pelagic limestone succession devoid of terrigenous components in Sicily to a considerably thicker neritic Tunisian succession containing terrigenous nd carbonate rocks. Differences in stratigraphic character across the shelf relate to the relative position of Sicily and Tunisia between the unstable and subsident Tethyan margin and the stable and emergent Saharan platform. As the North African continental margin subducted northward beneath the accretionary Kabyle-Calabrian belt in the late Cenozoic, the thin carbonate successions of Sicily responded by detaching in a series of southward-migrating thrust sheets. Along strike in Tunisia, the thrust sheets die out and stress was taken up by folding the thick marly succession weakened by numerous Late Triassic evaporite diapirs. Despite differences in structural style, the orientations of the structures in both Tunisia and Sicily have been guided by the crustal template created by middle esozoic rifting. Hydrocarbons on the Tunisian-Sicily shelf are related to (1) Mesozoic or younger structures that deform the early Paleozoic black shale-orthoquartzite succession of the Saharan platform, (2) synrift anoxic basin facies, (3) the Cretaceous-early Cenozoic shelf margin in the Tunisian section, and (4) late Cenozoic synorogenic clastic facies. End_of_Article - Last_Page 305

The Neiva and Girardot basins of the upper Magdalena Valley are en echelon late Cenozoic structural depressions between the Central and Eastern Cordillera of the Colombian Andes. The basins contain three depositional sequences up to 9,000 m thick resting on Paleozoic crystalline basement: (1) a Triassic-Jurassic nonmarine clastic and minor carbonate sequence, (2) a middle Cretaceous to Paleogene marine to nonmarine clastic and minor carbonate sequence, and (3) a thick Neogene nonmarine molasse sequence. The Andean orogeny in the upper Magdalena Valley occurred in two phases: (1) late Oligocene-early Miocene (Neiva basin), and (2) late Miocene-Pliocene (Neiva and Girardot basins). The first phase was dominated by basement-cored domes and basement-driven thrusts displaced toward the east from the Central Cordillera, while the second phase was dominated by basement-driven thrusting toward the west from the Eastern Cordillera. The basement-rooted thrusts splay upward within the Cretaceous and Paleogene strata and form complex shallow to moderate-dipping thrust sheets or terminate within the sedimentary cover to form a series of tight folds. From middle Miocene to late Pliocene, a thick molasse sequence accumulated on the earlier structures in both basins. During the younger phase of defo mation, the molasse was deformed by continued movement on basement-rooted faults. The basement-driven structures in the upper Magdalena Valley are probably the result of transpressional movements along the eastern margin of the Andean volcanic arc in the Central Cordillera. End_of_Article - Last_Page 555

The Gebel Gharamul region in the western Gulf of Suez offers an excellent outcrop example of the structural geometries associated with an accommodation zone termination. The surface expression of the accommodation zone is dominated by a basement promontory, which protrudes from the rift shoulder and underlies the junction of oblique ramps from two adjacent half-grabens, both of which face the Gulf of Suez. The southern half-graben represents the breakaway fault of the southwest-dipping tilt-block domain, and the northern half-graben represents the collapse of the upper plate above the northeast-dipping tilt-block domain. Basement and Nubian rocks in the hanging walls above the opposing low-angle detachments on either side of the accommodation zone are broken by gulf-parallel synthetic normal faults and orthogonal transfer faults, which act as block terminations and incrementally accommodate the large-scale rotation and displacement between adjacent blocks. The prerift and synrift stratigraphic succession is draped over this fault template, resulting in a complex and variable distribution of structures, the product of an inhomogeneous stratigraphic succession within an accommodation zone.

Many traditional terms for fault-related rocks have undergone recent dynamic metamorphism under high-pressure discussions by various groups of specialists. A generally acceptable simplified framework encompassing these and associated structural terms is now needed for many geologic, engineering, and legal purposes. Such a framework is proposed here, focusing on a rate-of-strain versus rate-of-recovery diagram and relating this framework to the products of brittle and ductile deformation along faults.

The sedimentary response to early Miocene fault reactivation and marginal uplift in the Gulf of Suez is strikingly evident within the Gemsa half-graben. This mid-Rudeis event occurred in the late Burdigalian (16.5 Ma) approximately 8 m.y. after the onset of rifting. In outcrop, complicated lateral facies transitions reflect the change from a ramped margin to a structurally controlled depositional environment. Angular unconformities and truncation mark this event atop marginal tilt-block crests. Distal downlapping sequences are present in adjacent topographic lows that acted as sand depocenters. Channels draining the rift margins acted as point sources for basinward alluvial-fan development. Sand-ratio isopach maps reveal the presence of four active upper Rudeis Formation fan systems within the Gemsa half-graben.

Recent seismic reflection profiling in western Georgia and adjacent eastern Alabama, conducted by the Consortium for Continental Reflection Profiling (COCORP), shows that reflections commonly associated with the Appalachian detachment do not continue southeastward beneath the Pine Mountain belt. Rather, these reflections terminate abruptly on the north side of the belt, along the downdip projection of the Towaliga fault. This observation is difficult to reconcile with the basement duplex interpretation traditionally applied to the Pine Mountain belt and to all other Appalachian interior basement massifs. An alternative interpretation, consistent with the reflection data and with local surface geologic relations, is that the Towaliga fault is, at least in its later evolution, a large northwest-dipping normal fault that cuts the Piedmont allochthon, Appalachian detachment, and Grenville basement. Where crossed by the COCORP profile, this fault has an inferred average dip of about 54° and offsets Grenville basement about 9 km. This interpretation is consistent with the view that the Pine Mountain belt is a structural window through the Piedmont allochthon. However, it implies that much of the structural relief on the basement exposed in the window is due to late normal faulting rather than to thrust imbrication alone. If correct, this has several important implications for Appalachian geology: (1) It implies that normal faulting of late Paleozoic and/or Mesozoic age has played a much more important role in the development of the exposed southern Appalachians than has generally been considered to date. (2) Grenville basement exposed in the Pine Mountain belt has been attached to North America since Precambrian time; it does not represent a Paleozoic accreted terrane. (3) The Appalachian detachment may be exposed around the periphery of the Pine Mountain belt and hence may be available for direct observation at this locality.

This study presents a classification/characterization of Appalachian faults. Characterization factors include timing of movement relative to folding, metamorphism, and plutonism; tectonic position in the orogen; relations to existing anisotropies in the rock masses; involvement of particular rock units and their ages, as well as the standard Andersonian distinctions. Categories include faults with demonstrable Cenozoic activity, wildflysch-associated thrusts, foreland bedding-plane thrusts, premetamorphic to synmetamorphic thrusts in medium- to high-grade terranes, postmetamorphic thrusts in medium- to high- grade terranes, thrusts rooted in Precambrian basement, reverse faults, strike-slip faults, normal (block) faults, compound faults, structural lineaments, faults associated with local centers of disturbance, and geomorphic (nontectonic) faults.