We propose five hypothesis concerning small intraplate earthquakes and the possibility that they are triggered by fluid injection. The proposed hypotheses are based on empirical observations but are consistent with the generally accepted ideas that small intraplate earthquakes are ubiquitous and occur on preexisting faults in response to regional tectonic stress and that injected fluids can induce seismic slip by reducing normal stress and hence fault strength. Although these hypotheses are not yet proven, they serve as a template for additional research. They also provide a basis for making decisions that reduce the likelihood of triggering earthquakes and for mitigating potential seismic hazard associated with injection activities.
Successful production performances from shale resources in North America have generated broad interests in several intriguing properties, such as organic-matter pore network, wettability, connate-water saturation, geopressure gradient, and brittleness. Although poorly understood, unique characteristics of these properties can have profound impacts on storage capacity, fluid flow, and production. Objectives of this study were to investigate potential effects of organic-matter pore network, wettability, low connate-water saturation, geopressure gradient, and effective stress on properties of organic-rich shales as well as fluid flow through shale reservoirs.
This chapter reviews petrographic evidence concerning the mechanisms by which mudrocks lithify. Mudrocks clearly undergo processes analogous to compaction and cementation in sandstone and limestone, although the relative importance of these two processes in the diagenesis of mudrocks remains uncertain. Cement in mudrocks can be demonstrated to fill both primary and secondary pores. Inter- and intragranular cements are observed in mudrocks as well as cement within fracture fills. Thus, cements in mudrocks take the full range of form and distribution as observed for cements in sandstone and limestone. Displacive precipitation is a chemical-mechanical process observed with particular frequency in mudrocks, which contrasts with the common cementation processes in sandstones and limestones. Overall, the same authigenic minerals common in sandstone and limestone dominate the authigenic assemblages in mudrocks. Sediment accumulation rate is a significant factor in mudrock cementation. In situations of slow sediment accumulation, cement emplacement, typically in the form of highly localized carbonate and phosphate minerals, takes place near the sediment-water interface. In contrast, rapidly deposited mudrocks tend to lithify at greater depths in response to thermally controlled diagenetic reaction of the detrital assemblage. Authigenic quartz in mudrocks, a topic of particular interest for an understanding of mudrock mechanical properties, requires further study. Grain replacements and fracture fills of quartz are readily documented in mudrocks, but convincing demonstration of intergranular quartz cement remains elusive. High-resolution imaging by transmission electron microscopy may be required to fully resolve issues surrounding the emplacement of authigenic quartz into the minute pores of mudrocks.
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The phenomenon of rocks moving under their own means has always fascinated both scientists and the nonscientists. Salt is known to extrude and flow as a result of differences in density of the material and surrounding sediments. However, movement of fine-grained clastics as intrusive injectites or diapirs or as extrusive eruptive sand blows or mud volcanoes has captured the public’s imagination and given scientists the impetus to reconsider the physics of how sediments behave in the subsurface. The 2006 AAPG Hedberg Conference on Mobile Shale Basins was held in response to a need to gather industry and academic communities in a common forum to address the very existence of mobile shales. Because this question involved integrated understanding of argillokinesis from the grain scale to the basin-gravity scale, the forum attracted a broad cross section of the geoscience community. These attendees presented a wide variety of topical presentations that ranged from geochemistry of modern fluid-mud extrusions to gravity studies in basins characterized by mobile shales. An ongoing topic of debate at this forum was the very term ‘‘mobile shales.’’ The attendees decided at the meeting that this term was a misnomer and that a more appropriate term to be used to describe this phenomena was shale tectonics, thus the title of this volume. Stimulating and informative discussions at the Hedberg conference led to this special volume on shale tectonics, with contributions from researchers in industry, academia, and government covering diverse aspects of shale tectonics from grain to basin scale. In addition, to works from authors who attended the Hedberg conference, this book also contains articles from authors who did not have an opportunity to present their work at the meeting. We hope this volume presents a representative cross section of the most current research and understanding regarding shale tectonics. The volume documents shale tectonics from a variety of basins around the world, including the southern Beaufort Sea (Elsley and Tieman, 2010), the KrishnaGodavari Basin, India (Choudhuri et al., 2010), the Niger Delta (Wiener et al., 2010), eastern offshore Trinidad (De Landro Clarke, 2010), offshore Brunei (Warren et al., 2010), and along the Spanish arm of the Mediterranean Sea (Soto et al., 2010). Publication of this memoir coincides with a growing interest in shales as hydrocarbon reservoirs. Because of the burgeoning of shale gas and shale oil research, geoscientists are gaining a better understanding of the petrographic framework of shales, as well as their behavior under various pressure and temperature regimes and the manner in how fluids move thorough these strata (for a review, see Day-Stirrat et al., 2010). Advances in seismic imaging and processing technologies illuminate stratal geometries associated with shale tectonics that have led to a new understanding of the processes responsible for the geometries we observe in shale strata (see Day-Stirrat et al., 2010; Elsley and Tieman, 2010). In addition, advances in modeling and understanding of how both muds and shales behave after burial have led to new geodynamic models for interpreting process from response reflected in stratal packages (Albertz et al., 2010). Field geoscientists have added to our understanding of the geochemistry and physical character of extrusive mud features and their relationship to the overall basin hydrocarbon system (Battani et al., 2010;
Oil and gas volumes are controlled by top-seal capillary properties, spillpoints, and trap geometry. The top-seal capillary properties and seal capacity can be estimated from the equivalent grain size (EGS) method. The EGS method uses an experimentally derived relationship between pore-throat size, porosity, and grain size to evaluate seal capacity. A pure spillpoint-limited trap is one in which the hydrocarbon column height is determined solely by the spillpoints. The observed hydrocarbon column in this trap is less than that which can be held by top-seal capacity. This trap type will be dominated by gas. In a capillary and spillpoint mixed trap, where both oil and gas can be filled down to the spillpoint, both top-seal capacity and spillpoint control relative oil and gas column heights. A pure capillary-limited trap is that where the oil and gas are not filled down to the spillpoint. Top seal and spillpoint have been the focus of seal analyses; however, a case study for fields referred to as AN and YA in this chapter demonstrates an important relationship between trap geometry and top-seal capacity. These two fields have the same top-seal capacity, but the total column heights, as well as the relative oil and gas columns, are very different. This is explained by the different ratios of the base area to its relief in the two fields. The ratio of the area to its relief of the AN field is smaller, whereas that of the YA field is much larger. Given the same top-seal capacity, a trap with a higher area-to-relief ratio can hold a larger gas column because the oil pushed down by the migrated gas reduces its column height remarkably. Thus, the EGS method can provide new insights into understanding hydrocarbon fill patterns in fields and prospects, including fault traps.
The Miri Airport Road outcrop in Miri, Sarawak, exposes a weakly consolidated sandstone-mudstone sequence of Miocene age in the form of a gentle anticline cut by a series of normal faults. An outcrop study of the normal faults shows that fault zones in porous sandstones are characterized by a combination of shale smear and anastomosing deformation bands. The continuity of shale smear on fault offset was observed as having a shale-smear factor (fault throw divided by shale layer thickness) of at least 5. Deformation bands occur as solitary planar structures in the host sandstone away from fault zones but increase markedly in density and linkage toward the fault slip plane, possibly indicating that faulting evolves from individual bands to a high-strain zone characterized by anastomosing deformation bands and culminating in the fault slip plane. Gas-permeability measurements show that individual deformation bands have an order of magnitude lower permeability than in the nearby sandstone matrix, and that the lowest permeability of fault zones defined by anastomosing deformation bands is in traverses nearly perpendicular to fault planes. It was found that the sandstone matrix in the fault zone has a lower permeability than individual deformation bands outside the fault zone, indicating that as a whole, the fault zone undergoes tectonic compaction and porosity collapse. The development of major normal faults was also accompanied by reactivation of bedding-perpendicular joints as small-displacement, simple-shear faults between the major faults.
The Erawan field in the Gulf of Thailand is characterized by a series of east- and west-dipping normal faults displacing the Miocene clastic reservoirs. The fault-seal capacity of these faults was assessed using sand-shale juxtaposition diagrams, shale smear parameters, and fault-seal failure probability (FSFP) (based on in-situ stress conditions). For this study, five east-dipping faults in the Erawan N Platform area were selected (faults E-16, E-17, E-18, E-20, and E-27). Several deviated wells have been drilled through the footwall blocks of these faults. Low values of the shale smear factor (SSF 6) and high values of the clay content ratio (CCR 30%) of four of the faults suggest that faults seal along their planes. In contrast to these four faults, fault E-27 appears to act as an across-fault conduit for some intervals and seal in others. Intervals without trapped hydrocarbons have higher SSF values, suggesting that the fault leaks locally. These five faults trap 15 gas pay zones. Eight of the pay zones have sand-shale juxtaposition across the faults, which may explain 8 of the 15 accumulations. Shale smear parameters can account for all 15 accumulations. Fault-seal failure probability was derived for one of these faults (E-16) by integrating the CCR values and the probability of fault slip tendency and fault dilation tendency under the current stress regime in the Erawan field. Low FSFP values indicate that the fault seals do not appear to have been breached given the in-situ stress field acting on the normal fault.
The Temana field is located on a structural high in the Balingian province, offshore Sarawak, Malaysia. Fault-sealing assessment of a normal fault in the Tertiary clastic rocks of the Temana field was carried out using shale smear parameters. Shale smear factor values of less than 6 and clay content ratio of greater than 30% on the fault surface indicate across-fault sealing of the reservoir rocks on sand-sand interfaces. Hydrocarbon column height estimated for sandstone pay zones from across-fault pressure difference is comparable to that calculated from the structural spillpoint (76 m; 249 ft). The fault seal thus appears to be efficient enough to support hydrocarbon columns filled down to the structural spillpoints of the reservoirs. Fault-rock permeability calculated from the available calibrations of the clay content-permeability relationship shows lower permeabilities of less than 0.3 md. Taking the Temana fault as a case in point, a new approach to evaluate fault-rock permeability probability (based on integration of clay content, fault displacement, and depth factors) is presented.
Combined electron microbeam imaging techniques can be used to quantify cementation and compaction processes in deformation bands and their surrounding host rocks. Mixed secondary and backscattered electron signals can be used to definitively identify pore space, whereas scanned cathodoluminescence can be used to discriminate between detrital and authigenic quartz. Classic deformation bands from three porous sandstone units, the Cambrian Hickory Sandstone of central Texas (two bands and two host rocks), the Pennsylvanian Tensleep Sandstone of Wyoming (one band and one host rock), and the Pennsylvanian Weber Sandstone of northwestern Colorado (one band and one host rock), were examined using these imaging techniques. Cathodoluminescence images demonstrate that bands develop through a combination of grain-scale brittle processes and cementation. Point counting of scanning electron microscopy image mosaics reveals that the intergranular volume in deformation bands is higher than is apparent from transmitted light microscopy. Cementation equals or exceeds compaction as a cause of porosity decline in both deformation bands and host rocks. No evidence exists for significant pressure solution during band development. The intergranular volumes of host rocks in the range of 31–38% suggest that all of these samples have experienced burial of 2 km (1.2 mi) or less. Contrasts in the compactional and cementational states of bands and surrounding host rocks possibly reflect the differing availability of quartz nucleation surfaces in these different parts of the rock. Preferential emplacement of cement in the bands can lead to divergent paths of compactional behavior in bands relative to host rocks during the postkinematic phase of their burial history.
To refine flow models for sand-dominated fault rock, we present petrophysical data of host and fault rock samples from the eolian Aztec Sandstone, Valley of Fire State Park, Nevada, that has been deformed by strike-slip faults formed by progressive shearing along joint zones. The data include bulk mineralogy, porosity, permeability, grain-size distribution, and mercury-injection capillary pressure measurements of 40 host, fragmented, and fault rock samples. To investigate the impact of shear strain on fault zone properties, three sample localities with average shear strains of 28, 63, and 80 were investigated (25–160-m [82–525-ft] slip). No bulk mineralogical changes caused by fault zone cementation or mineral alteration were detected when comparing host and fault rock. Fault rock permeability is one to three orders of magnitude lower than median host rock permeability. Porosity reductions are less pronounced and show considerable overlap in values between the sample suites. Some fault rock samples appear to have dilated with respect to median host rock porosity. Median grain sizes for fault rock samples range from 3 to 51 m, which is as much as two orders of magnitude reduction from host rock median grain sizes. There appears to be a lower limit of median grain size of 3 m for fault rock samples irrespective of average fault shear strain. Fault rock capillary injection pressures range from one to almost two orders of magnitude higher than the host rock equivalent. For standard fluid properties, calculated maximum sealable hydrocarbon column heights range between 10 and 70 m (33 and 230 ft) of gas and 20–120 m (66–400 ft) of oil. These petrophysical data show that faults formed by shearing of joints in high-permeability, sand-prone systems will act as significant barriers to fluid flow during reservoir production and might be capable of sealing small to moderate hydrocarbon columns on an exploration timescale as well, assuming adequate continuity of the fault rock over large areas of the fault.
We examined the distribution of fault rock and damage zone structures in sandstone and shale along the Moab fault, a basin-scale normal fault with nearly 1 km (0.62 mi) of throw, in southeast Utah. We find that fault rock and damage zone structures vary along strike and dip. Variations are related to changes in fault geometry, faulted slip, lithology, and the mechanism of faulting. In sandstone, we differentiated two structural assemblages: (1) deformation bands, zones of deformation bands, and polished slip surfaces and (2) joints, sheared joints, and breccia. These structural assemblages result from the deformation band-based mechanism and the joint-based mechanism, respectively. Along the Moab fault, where both types of structures are present, joint-based deformation is always younger. Where shale is juxtaposed against the fault, a third faulting mechanism, smearing of shale by ductile deformation and associated shale fault rocks, occurs. Based on the knowledge of these three mechanisms, we projected the distribution of their structural products in three dimensions along idealized fault surfaces and evaluated the potential effect on fluid and hydrocarbon flow. We contend that these mechanisms could be used to facilitate predictions of fault and damage zone structures and their permeability from limited data sets.
Sandbox analog modeling experiments provide new insights into the effects of fault geometry on reservoir connectivity. During progressive distributed extension, three phases of fault system evolution are apparent. In Phase I, geometrically simple faults nucleate rapidly at a large number of sites throughout the deforming region. This is followed by Phase II, in which faults link and increase in trace length. Phase III is characterized by a quasi-steady-state nucleation and linkage of faults. Reservoir connectivity has many components; here, we focus on fault-controlled connectivity, which can be viewed from two complementary perspectives: rock mass connectivity (continuity of rock between and around faults) and fault network connectivity. Which of these perspectives is adopted depends on whether faults cutting the reservoir act as barriers to flow (e.g., in highly porous sandstone reservoirs) or conduits for flow (e.g., in fractured carbonate reservoirs). We use two measures of fault-controlled connectivity: (1) a fault density measure derived from the number of intersections between faults and potential flow paths and (2) the ratio of the number of fault tips to the number of faults. Taken together, these characteristics convey both the transmissivity characteristics and the ultimate leakiness of the reservoir.
Fault gouges were mapped and collected along the Atotsugawa fault, one of the major active faults in Japan, and along the Mozumi–Sukenobu fault, branching off from the Atotsugawa fault. Most of the fault gouge samples contain mica clay minerals, chlorite, smectite, and quartz. To constrain the timing of faulting, K-Ar and x-ray diffraction analyses (XRD) were carried out on mica clay minerals separated from the gouge samples. Each gouge sample was divided into four grain-size fractions of 5–2, 2–1, 1–0.35, and 0.35–0.05 m. Kbler illite crystallinity indices for the finer grain-size fractions (0.05–1 m; illite crystallinity = 0.4–0.8) were found to be higher than those for the coarser fractions (1–5 m; illite crystallinity = 0.3–0.6), indicating the relatively higher concentration of authigenic mica clay minerals. The genesis of the clay minerals was probably related to hydrothermal alteration events associated with fault activity in the finer fractions. K-Ar ages were younger for the finer fractions of all samples. One sample from the Atotsugawa fault yields the youngest age of 61 Ma for the finer two fractions, which probably dates the thermal activity associated with the fault because of a similar age for the finer two fractions. This also suggests that the contamination of protolith mica is negligible for these samples. The finest fraction of the Mozumi–Sukenobu fault gouge derived from the interbedded sandstone and mudstone of the Tetori Group (Upper Jurassic–Lower Cretaceous) gives a K-Ar age of 45 Ma. Although this gouge sample is derived from mudstone and sandstone and, thus, the contamination of protolith illite cannot be identified by illite crystallinity, the age probably approximates that of a hydrothermal alteration event associated with the fault activity, because the age is significantly younger than the sedimentary age of the protolith Tetori Group. These K-Ar ages from the Atotsugawa and Mozumi–Sukenobu faults are compared with previous K-Ar ages of fault gouges from major active faults in Japan, including the Median Tectonic Line in Shikoku–Kinki and the Atera fault. The K-Ar data from these faults indicate that the major active faults in the Inner Zone of Southwest Japan were initiated at 60–50 Ma. Heterogeneity in and around the Late Cretaceous granitic terrane, especially the boundary of rigid granitic body and soft accretionary complex, seems to be the preferred sites for fault initiation.
Ever since Frederick Clapp included fault structures as significant petroleum traps in his landmark paper in 1910, the myriad function of faults in petroleum migration and accumulation in sedimentary basins has drawn increasing attention. Fault analyses in petroleum traps have grown along two distinct and successive lines of thought: (1) fault closures and (2) fault-rock seals. Through most of the last century, geometric closure of fault traps and reservoir seal juxtaposition by faults were the focus of research and industrial application. These research and applications were made as structural geology developed quantitative methods for geometric and kinematic analyses of sedimentary basins, and plate tectonics offered a unified tool to correlate faults and basins on the basis of the nature of plate boundaries to produce stress. Over the last two decades, compartmentalization of reservoirs by fault seals has been more intensively investigated as three-dimensional seismic images better resolve fault structures. Geometric characterization of fault architecture, identification of various sealing processes in fault zones, and quantitative appraisal of petrophysical properties of fault rocks have significantly advanced in recent decades. Fault-seal analyses have shifted from two-dimensional fault juxtapositions to three-dimensional models encompassing fault surfaces, fault transmissibility, and juxtaposed reservoir units. Current methodologies for fault-seal assessment mostly address normal faults in clastic reservoirs. Fault sealing processes in thrust faults and in carbonate reservoirs represent important blind spots in our knowledge. Shale smear has been effectively applied for sealing assessment of syndepositional faults in sandstone-claystone successions. However, fault-seal analyses based merely on shale smear ignore other important sealing processes, notably cataclasis and cementation in fault zones. During their active stages, faults are conduits of subsurface fluids, irrespective of any sealing mechanism that operated before fault rupture. Therefore, a comprehensive fault-seal assessment needs to be a four-dimensional model integrating fault motions, fault-zone processes, and fluid flow. This remains a major challenge. However, integration of in-situ fault stress analysis and fault-seal analysis has provided a technological breakthrough. The realization that fault rocks are low-permeability and high-capillarity features in sedimentary basins has given an economic impetus for exploration of fault traps. The shift from modeling of single-phase fluid flow to multiphase or even mixed-phase fluid flow along and across fault zones will be of more value to these exploration efforts. Recent studies have transformed the old polarized view of faults as either leaks or seals into realistic notions of more complex fault-fluid flow behavior. Current shortcomings in fault-seal assessment are largely caused by the scarcity of detailed data and the need for robust calibration of numerical models. This implies that empirical data will form the cornerstone of near-future advances in fault-seal methodologies.
Large reserves remain and are economically recoverable in many mature oil fields. This study documents the successful search for such overlooked reserves in old fields. Small multidisciplinary teams studied several basins in North America and a few large fields in South America, searching for large volumes of low-risk reserves in poorly performing fields. The fields studied included those producing by primary recovery, with or without secondary recovery potential, as well as fields undergoing waterflooding. In the United States, more than 350 mature oil fields were evaluated for potential purchase from 1981 to 1997. The majority of the fields were in the Permian Basin of west Texas-New Mexico and in a coastal portion of the Gulf of Mexico Basin. In addition, some large fields were studied so property owners could be advised on rejuvenating or increasing production.Finding large volumes of low-risk, presently nonproducing reserves within fields involves several steps. First, the teams search in reservoir systems that appear more massive and homogeneous than they really are. Second, the geoscience and engineering data are scanned to estimate original oil in place, percent recovery, and bypassed reserves. Third, the teams make an economic analysis, including improvement costs. Fields that are candidates for purchase have discovered low- to moderate-risk reserves amounting to at least 5% of the cumulative reserves already produced,New reserves are discovered or exploited by applying one or more of the following: (1) improved drilling and completion technology; (2) identification of bypassed pay, especially very low resistivity pay; (3) new 2-D and 3-D seismic surveys; and (4) sequence-stratigraphic concepts. Additional reserves are found in both land-derived clastic and carbonate reservoirs in mature fields.Forty-six mature fields were purchased in the Permian Basin of Texas-New Mexico and in the Gulf of Mexico Basin. In the fields purchased, 625 million barrels of oil equivalent (BOE) of proved and probable reservoirs were added at a cost of US $2.69/BOE. The average after-tax rate of return of the 46 fields is 21%. Based on these results, "exploring for new oil in old places" is an economically viable strategy for adding hydrocarbons to the world's reserves base.
Onshore China has more than 20 major sedimentary basins. Significant oil production is currently limited to only three basins-Songliao, Bohaiwan, and Junggar. Exploration results in some of the other onshore basins have been disappointing; in others, activities have been limited because of their remoteness. This paper focuses primarily on the Junggar and Tarim Basins because of their large size and potential for significant oil and gas discoveries. Hydrocarbons discovered in the three producing basins appear to have been derived from mainly lacustrine systems and are often found in nonmarine sandstone reservoirs. The oils found are often waxy and reservoir properties are poor, with limited vertical and lateral continuity. Consequently, although field sizes may be large, flow rates from individual wells may be limited, requiring a large number of wells to capture the reserves. For example, Daqing field (Songliao Basin) had initial reserves of more than 8 billion barrels (bbl) of oil and is producing similar to1.1 million bbl/day, but it contains more than 10,000 wells. Similarly, typical flow rates from vertical wells in the Shengli petroleum province (Bohaiwan Basin) are less than 700 bbl/day. Recent horizontal wells in Shengli field have shown significant improvements in production rates, with individual wells achieving rates of more than 5000 bbl/day. An examination of the less well explored basins suggests that many of the key components of petroleum systems are present. For example, in the Tarim Basin, multiple marine and lacustrine source rocks have been identified, as have both siliciclastic and carbonate reservoirs ranging in age from Cambrian-Ordovician through Paleogene. Active seeps have also been observed in the basin and more than 200 structural targets have been identified, with more than half of them having surface expression. The primary exploration challenges in many of these basins appear to be associated with relative timing, preservation of hydrocarbon accumulations, and communication between the generative basin and the trap.
Remaining reserves of marketable crude oil and natural gas in Canada are more than 1.43 billion [10(9)] m(3) (9 billion bbl) and 1.84 trillion [10(12)] m(3) (65 trillion cubic feet [tcf]), respectively. These reserves enable current annual extraction rates of 127 million m(3) (800 million bbl) of oil and 170 billion m(3) (6 tcf) of natural gas, mainly from the mature Western Canada Sedimentary Basin. In the new millennium, expanded contributions to production capacity will come initially from the Mesozoic Jeanne d'Arc Basin (e.g., Hibernia and Terra Nova oil) offshore Newfoundland and from basins off Nova Scotia (e.g., Sable Island gas). In northern Alberta, additional investment in exploiting the Cretaceous oil sands will enhance the production of upgraded (synthetic) crude oil, bitumen, and heavy oil.Notwithstanding the technical and commercial challenges, predictions of remaining exploitable resources in accessible areas exceed 5.6 trillion m(3) (200 tcf) of gas and 16 billion m(3) (100 billion bbl) of bitumen. In addition to oil sands, tight gas, and coal-bed methane in the Western Canada Sedimentary Basin, significant undeveloped resources are known in the remote Canadian Arctic islands (Sverdrup Basin), the Labrador shelf (gas), and the Beaufort Basin (gas and oil). Many of these resources will remain "orphaned," depending on environmental aspects, delivery costs, markets, and commodity prices. Current "stranded gas" in the Mackenzie Delta and the shallow offshore waters of the Beaufort Sea will be connected (via the Mackenzie Valley corridor) to the natural-gas pipeline grid serving Canadian and United States markets. Associated gas reserves (presently reinjected at Hibernia) in the Jeanne d'Arc Basin, if not connected to shore by pipeline, may be developed using either natural-gas-to-liquid conversion or compressed-gas transport technologies.Canada's resource base is not in crisis, but the rate of conversion of the resource base to productive capacity cannot be as rapid as the resource potential might suggest.
Recoverable reserves in approximately 320 fields in Libya's Sirt, Ghadamis, Murzuq, and Tripolitania Basins exceed 50 billion barrels of oil and 40 trillion cubic feet of gas. Approximately 80% of these reserves were discovered prior to 1970. Since then, there has been a less active and more conservative exploration effort. Complex, subtle and, in particular, deep plays were rarely pursued during the 1970s and 1980s because of definitive imaging technologies, limited knowledge of the petroleum systems, high costs, and risk adversity. Consequently, extensive undiscovered resources remain in Libya. These resources could be accessed if geologic and geophysical knowledge, innovation, and advanced technologies were used effectively. Three-dimensional seismic acquisition will be required to some degree for reliable trap definition and stratigraphic control. Predictably, most of the undiscovered resources will be found in the vast, underexplored deep areas of the producing basins. Six areas are exceptional in this regard: the south Ajdabiya trough, the central Maradah graben, and the south Zallah trough-Tumayam trough in the Sirt Basin, and the central Ghadamis Basin, the central Murzuq Basin, and the offshore eastern Tripolitania Basin in the west. These highly prospective basin sectors encompass a total area of nearly 150,000 km(2), with an average well density for wells exceeding 12,000 ft of 1 well/5000 km(2).
The Mexican portion of the Gulf of Mexico Basin (MGOM) extends onshore into several oil- and/or gas-producing basins: Burgos, Tampico-Misantla, Veracruz, and Sureste (the Sureste Basin includes the Salina del Istmo, Comalcalco-Chiapas-Tabasco, Macuspana, Sonda de Campeche, and Litoral de Tabasco provinces). To the east, the MGOM includes the nonproducing Plataforma de Yucatan. The deep-water Gulf of Mexico has been subdivided into eight provinces: Franja Distensiva, Delta del Rio Bravo, Franja de Sal Aloctona, Cinturon Plegado de Perdido, Cordilleras Mexicanas, Canon de Veracruz, Salina del Golfo Profundo, and Planicie Abisal. Based on the petroleum systems and exploration history of these provinces, most undiscovered reserves are likely to be found in the deep water of the MGOM.
