Abstract The Central Sumatra basin contains the Pematang-Sihapas(!) petroleum system, the most prolific petroleum system in southeastern Asia. A chronostratigraphic framework based on well logs and cores provides insights concerning the occurrence of seals, reservoirs, and the distribution of hydrocarbons. Oil sourced from lacustrine lithofacies of the Pematang Group ( i.e. , the Brown Shale) in the underlying rift sequence migrated vertically until reaching a thick paleosol horizon (representing the 25.5 Ma sequence boundary). Thereafter, oil migrated toward the eastern margin of the basin charging the giant Minas and Duri fields. Erosional truncation (incised valley development) of paleosols and faults provided “windows” for migration of oil into overlying Miocene (Sihapas Group) marine, sandstone reservoirs. Well log correlations and core data reveal the common presence of incision along the 25.5, 22, 21, and 17.5 Ma sequence boundaries. Oil accumulated preferentially in basal transgressive sandstones. Approximately 80 percent of the recoverable oil resides in the lower part of the 21 Ma depositional sequence. These well sorted, medium-grained sandstones (Bekasap Formation) record deposition in estuarine (presumably macro-tidal) settings. Marine sandstones within the overlying 16.5 and 15.5 Ma depositional sequences are oil-saturated; however, they are very fine-grained and have inherently low permeability. The regional top seal for Sihapas reservoirs is formed by calcite-cemented, glauconitic shales and siltstones (Telisa Group) that record the maximum Miocene transgression. Relatively small oil accumulations in the underlying alluvial-fluvial and lacustrine sandstones of the Pematang Group are sealed by paleosols. The permeability of the fluvial reservoirs is degraded by poor sorting and pervasive authigenic kaolinite. In distinct contrast, Sihapas sandstones have undergone minimal diagenesis. This newly developed sequence stratigraphic framework has dramatically improved the understanding of the correlation and distribution of Miocene hydrocarbon reservoirs and seals in Central Sumatran oil fields.

Abstract The goal of this research is to develop a predictive model for use in hydrocarbon exploration and risk analysis/mitigation that permits estimation of the sealing capacity of marine mudrocks. Research to date has concentrated on Cretaceous shales of the Western Interior foreland basin in Colorado and Wyoming and Eocene shales in the Ventura basin, California. This research focuses on Eocene rocks of the central Pyrenean foreland basin, Spain. Outcrop mudrock samples were collected from areas around Ainsa, Broto, Undues, and Anso in northeastern Spain. Geologically the areas sampled include the Ainsa basin slope, Broto base of slope, and the Jaca outer fan and basin plain in the south-central Pyrenees. Extensive research to define stratigraphic relationships, depositional environments, basin type, and sandstone body geometry have been undertaken, however the nature and sealing capacity of included mudrocks have been largely ignored. The Eocene Ainsa basin, from which most of our samples were taken, originated as a foredeep ahead of a thrust ramp and evolved into a piggy back setting as the thrust migrated basinward. This foredeep was filled with up to 4000m of slope sandstones and mudrocks, had a source area to the southeast and a basin plain (the Jaca basin) to the northeast. Sealing capacity of these mudrocks was determined by mercury injection-capillary pressure (MICP) measurements conducted by Poro-Technology on 43 samples representing a range of slope, base of slope, and basin floor environments. Capillary pressure curves generated during mercury injection have been used to evaluate sealing capacity by equating it to the pressure required to achieve 10%mercury saturation. Pore throat diameter was determined from data generated during the MICP analyses. Bioturbation was characterized on a qualitative scale of 0 to 6. Mean quartz grain size was determined by measuring the apparent long axes of thirty quartz grains per sample. Total organic carbon (TOC) and CaCO 3 were determined by analytical techniques in the soils laboratory at Colorado State University Samples analyzed range from laminated and bioturbated, calcareous mudstones to silty biomicrites and calcareous siltstones. Some samples contain thin, normally graded, laminations of silt-size quartz grains. MICP values at 10%saturation range from 500 PSIA to more than 60,000 PSIA. Despite the high degree of variability in samples from a single outcrop and from each sampled area there is a general correspondence with geographic and sequence stratigraphic setting. Furthermore, significant correlations exist between MICP and sample porosity, pore aperture diameter, standard deviation of pore diameter, and TOC. As expected sample porosity, pore diameter and standard deviation of pore diameter are inversely related to sealing capacity. TOC is directly related to sealing capacity. Degree of bioturbation is more variable in samples with low sealing capacity and is generally lower in samples with high sealing capacity. There are no apparent correlations between MICP and permeability, grain density, average quartz grain size, standard deviation of quartz grain size, quartz grain roundness, standard deviation of quartz grain roundness, or CaCO 3 content. From a depositional setting and sequence stratigraphic viewpoint proximal slope deposits have the lowest average sealing capacity, highest porosity and permeability, highest pore aperture diameter and most poorly sorted pore diameters, highest overall grain size and degree of bioturbation, and lowest TOC. Basin floor deposits have the highest average sealing capacity, lowest porosity and permeability, smallest pore aperture diameter, and best sorted pore diameters, lowest overall grain size and degree of bioturbation, and highest TOC. Compositional variables, other than TOC, are less important than textural variables in determining the sealing capacity of these mudrocks. Factors that influence the relative sealing capacity of these carbonate-rich mudstones are generally similar to those for non-calcareous shales from other foreland basins and include overall grain size, degree of disruption of depositional fabric by bioturbation, pore throat size and sorting, TOC, and depositional setting within the basin. The variables that most strongly favor high sealing capacity are most likely associated with deposits of deep water anoxic environments, hence the common association between good seals and upper transgressive systems tract deposits and condensed sections.

Abstract Sealing characteristics of marine shales are among the least understood aspects of petroleum systems. Petrophysical measurements indicate that the largest interconnected pore throats ultimately control seal behavior. Pore throat diameter, determined from mercury-injection capillary pressure (MICP) analysis, is influenced by numerous factors, including: composition (total clay content, and organic enrichment), fabric and texture (fissility, silt content and bioturbation), and diagenesis. Data from deepwater wells in the Gulf of Mexico and offshore Angola document the variability of shale microfacies and sealing character in marine depositional settings. This variability can be quantified and predicted where considered within the context of sequence stratigraphy and shale sedimentology. The analyzed Tertiary-aged marine shales record deposition in middle to lower slope paleoenvironments and are interstratified with sandstones representing lowstand fan lithofacies. Six shale microfacies can be defined based on differences in fabric and petrophysical properties: 1) well-laminated, slightly silty, organically-enriched shales; 2) moderately silty, partially laminated shales; 3) moderately silty mottled shales; 4) very silty mottled shales; 5) very silty shales interlaminated with siltstones and very fine sandstones; and 6) calcareous shales and claystones. Shale types 1, 2 and 6 consistently exhibit better than average seal capacities. Shale types 3 and 4 are moderate to good seals, and Type 5 shales are typically poor to very poor seals. Top seal capacity increases as clay content increases and decreases as the content of detrital silt increases. Depositional fabric appears to exert primary control on seal character, and early marine cementation can significantly enhance seal capacity. The texture and composition of marine shales vary systematically within depositional sequences and correlate with variations in sealing capacity. Silt-rich shales in highstand and lowstand systems tracts have 10% non-wetting (MICP) saturations that are consistently low relative to those of transgressive shales. The highest 10% non-wetting mercury-injection capillary pressure (MICP) saturations values correspond to transgressive and condensed shales containing significant percentages of authigenic carbonates. Shales occurring within the upper part of third-order transgressive systems tracts are typically excellent to exceptional top seals. These finely laminated, silt-poor, transgressive shales commonly have elevated percentages of organic matter and authigenic iron minerals. Seal capacity generally increases, basinward, from near shore to distal offshore marine settings. Where a transgressive shale is the controlling top seal for a lowstand reservoir, a thick waste zone commonly separates the seal and the subjacent reservoir.

Abstract A predictive model to estimate the distribution, sealing capacity and petrophysical properties of shale seals and flow barriers will significantly reduce the risks associated with hydrocarbon exploration and exploitation. Such a sequence stratigraphy-based predictive model must be grounded in outcrop and field analogs, such as this examination of the sealing capacity, petrophysical properties and distribution of Upper Cretaceous Lewis marine shales in two wells from south-central Wyoming. The measured sealing capacity of these shales varies with textural and compositional factors that allow division of the Lewis Shale depositional sequence six argillaceous microfacies. Each microfacies displays distinctive compositional and petrophysical properties and occupies a well-defined sequence stratigraphic position including transgressive, highstand, and condensed section deposits, with characteristic seal and seismic properties. The microfacies, in order of greatest seal capacity to least, are phosphatic shales, pyritic fissile shales, silty shales, silty calcareous shales, silty calcareous mudstones, and bioturbated argillaceous siltstones. The most promising seals, the phosphatic and pyritic shales, belong to the condensed section and uppermost transgressive systems tract. The phosphatic shale is also characterized by the highest content of both total organic carbon (TOC) and authigenic minerals. Interestingly, neither of these two high sealing capacity microfacies shows more detrital clay than other microfacies. The microfacies with lower sealing capacities belong to the highstand systems tract and are generally poorer in iron-rich minerals than the better sealing microfacies. Petrophysical properties, including high bulk density, shear velocity, Young’s modulus and shear modulus, distinguish the best sealing microfacies from highstand systems tract microfacies with poorer seal capacity. This correspondence between sealing capacity and petrophysical properties suggests that seismic data may have good potential as a tool for seal evaluation.

Abstract The Tenneco Phoenix #1 well (OCS-Y-0338) cored a nearly complete section through the Pebble Shale (Cretaceous), Sag River and Shublik Formations (Triassic), and the Eileen and Ivishak Formations (Permo-Triassic). Cores of the Shublik Formation and the underlying Eileen and Ivishak Formations. (7, 800 to 8, 200 ft) were subjected to detailed geochemical and sedimentological analyses. These cores allowed comprehensive study of source rock and reservoir lithofacies from a known petroleum system within a sequence stratigraphic context. The basal (reservoir) section of the studied interval (Ivishak Sandstone) records nonmarine (fluvial) deposition during highstand. The overlying Eileen and lower Shublik Formations are marine lithofacies that developed during a major transgression (source rock and seal lithofacies). A distinctive glauconitic, pyritic and phosphatic unit (condensed interval) occurs near the top of this transgressive interval. Overlying upper Shublik strata record deposition during highstand conditions. The distribution of oil-prone facies within the Shublik Formation is related to stratigraphic position and is predictable within a sequence stratigraphic framework. The lower (transgressive) part of the Shublik Formation is dominated by oil-prone facies, whereas upper (regressive) Shublik strata are predominantly gas-prone to nonsource. Ivishak sandstones in the Phoenix #1 well are equivalent to the main reservoir interval in the Prudhoe Bay field. These sandstones have average porosity ranging from 18 to 22 percent. Cross-stratified medium-grained Ivishak sandstones have average horizontal permeability that exceeds 2 Darcies. Other cored Ivishak lithofacies have average permeability values that range from 138 to 353 md. Compaction and the precipitation of quartz and siderite cements reduced the effectiveness of pore systems in Ivishak sandstones. Overlying Eileen sandstones are cemented pervasively with calcite. Marine shales (Shublik and Pebble Formations) provide potential seals for the North Slope Alaskan petroleum system.

Abstract Early Cretaceous rifting of the South Atlantic basin resulted in the development of three unconformity-bound tectono-stratigraphic megasequences that are recognizable in petroliferous basins along the present-day margins of both Brazil and west Africa. These megasequences have been termed nonmarine/synrift, transitional marine , and marine. These megasequences provide a framework for understanding the character and distribution of hydrocarbon reservoirs within the South Atlantic petroleum systems. Hydrocarbons occur in nonmarine and marine stratal packages in both carbonates and siliciclastics. Reservoirs in the marine megasequences contain an estimated 70% of the region's known oil reserves, most of which have been discovered in the last two decades in deep-water fields. Each reservoir system requires a comprehensive evaluation of depositional systems and diagenetic modification. Deep-water siliciclastic reservoirs are controlled by sediment provenance and transport mechanisms to the deep-water setting and less so by diagenesis. Synrift reservoirs are more affected by diagenesis, requiring detailed petrographic analysis. Carbonate reservoirs of the South Atlantic display the greatest degree of variability thus requiring detailed petrographic work. Our results suggest that the carbonate reservoirs have the most complex diagenetic profiles and must be related to the timing of hydrocarbon migration to better understand charge risk.

ABSTRACT This study of Kotabatak field (835 MMSTB OOIP) in the Central Sumatra Basin, Indonesia provides a case example of the application of sequence stratigraphy, based on the integration of core, wire-line log, and biostratigraphic data, as a predictive reservoir characterization tool for a proposed EOR (pattern waterflood) project. A peripheral waterflood (started 1981) has not performed as anticipated because previous studies of Kotabatak field failed to recognize the presence and significance of highly permeable incised valley-filling (IVF) sandstones. IVF sandstones typically have excellent reservoir characteristics, and thus, the recognition of IVF features has important implications for reservoir modeling studies. Lithofacies maps of Bekasap strata in Kotabatak field provide geologic explanations for field-wide variations in: oil production rates, remaining oil-in-place, water injection rates, and produced water. The Bekasap Formation is subdivided into three lithostratigraphic units (A-, B-, and C-Sands); the Bekasap A-Sand has accounted for most (80%) of the cumulative production (180 MMSTB) from Kotabatak Field. Four lithostratigraphic units (A-1, A-2, A-3, and A-4 sandstones) are recognized locally within the Bekasap A-Sand stratal package. Chronostratigraphic correlations reveal that IVF reservoirs are restricted to the Bekasap A-3 Sand. The A-3 Sand is underlain by the 21 ma sequence boundary. Bekasap A-3 incised valleys record the entrenchment of an estuarine channel complex into underlying offshore marine strata. This entrenchment of the estuarine depositional system has resulted in an abnormal vertical association of lithofacies wherein marginal marine (estuarine), and locally nonmarine (fluvial), strata directly overlie offshore marine lithofacies. Apparently, the intervening shallow marine lithofacies have been eroded during the basinward shift of estuarine processes. Bekasap A-3 (IVF) reservoirs consist mainly of tidally-influenced estuarine channel lithofacies; these sandstones have an average porosity of > 20% and an average horizontal permeability of 800 md (maximum 7.5 darcies). Characteristically, channelized Bekasap A-3 Sand reservoirs exhibit a strongly directional permeability parallel to the channel axis. In contrast, underlying Bekasap A-4 sandstones are fine-grained, glauconitic, profusely bioturbated lower shoreface lithofacies, representing a highstand systems tract (HST). The A-4 Sand has an average porosity of 15% and an average permeability of < 100 md. Because these IVF and HST sandstones have markedly different reservoir properties, Bekasap reservoirs within Kotabatak field are compartmentalized. Bekasap A-3 IVF sandstones occur preferentially in the northwestern area of Kotabatak field which, historically, has exhibited excellent reservoir performance. Low-permeability Bekasap A-4 Sand reservoirs are predominant in the southeastern area of Kotabatak field and are the target of a pilot pattern waterflood. Bekasap A-3 estuarine sandstones are overlain conformably by Bekasap A-2 / A-1 tidal lithofacies and comprise the lower part of a transgressive systems tract (TST). Uppermost Bekasap strata are overlain by the Telisa Formation which represents middle- to outer-shelf paleoenvironments of deposition. Telisa strata record the maximum mid-Miocene transgression and form the regional top seal for the giant oil accumulations within the Central Sumatra Basin. The study of Kotabatak field reservoirs demonstrates clearly that sequence stratigraphy is a powerful geologic tool for improving the understanding of stratal architecture and consequently field development strategies. The integration of sedimentologic, chronostratigraphic, and production-engineering data sets, at the field scale, is essential to the understanding of sandstone reservoir continuity and connectivity prior to reservoir simulation studies and the designing of EOR projects.

ABSTRACT The Aman Trough of Central Sumatra, Indonesia has two associated major hydrocarbon accumulations, Minas and Duri fields. As with most maturely explored basins, more recent exploration activities have involved smaller structural closures, often testing new or different exploration concepts. Sidingin Gas Field, discovered in 1989, is located on an isolated fault block on the northern end of the Aman Trough. Wells in the field encountered reservoir stratigraphy quite different from that encountered in most wells in the Aman Trough. The stratigraphy of the North Aman Trough demonstrates several scales of stratigraphic development: (1) a 2nd order tectonic (syn-rift) cycle, encompassing the entire Pematang Group (Oligocene), composed of stacked fluvial-lacustrine-fluvial members; (2) a series of higher order (3rd order?) sequences, best observed in the fluvial strata, composed of basal coarse fluvial sandstones overlain by floodplain shales; (3) parasequences of individual sandstone/shale couplets. The fluvial rocks in the North Aman Trough and in the Sidingin field are interpreted in terms of regularly varying and repeating base-level cycles. The sedimentology and stacking patterns can be explained in terms of lowered base-level producing highly erosional coarser-grained fluvial channel sands, likely autocyclic in origin, giving way to individual channel and splay sands deposited as base-level rose, and finally capped by a muddy floodplain shale interval. In many cases, the tops of the shale packages are capped with a paleosol, interpreted as a remnant subaerial exposure surface consistent with a relative lowering of base-level. Although well logs through Sidingin field display somewhat similar log character to wells within the Aman Trough proper, evaluation of seismic facies and petrography yielded different stratigraphic interpretations. The reservoir in Sidingin field is interpreted as an alluvial fan and fan delta interval, sourced by highlands associated with the rift basin border fault. The facies successions from oxidized, proximal alluvial fan to intercalated fan delta–lacustrine shale strata suggest that base-level variations related to the local structuring controlled stratigraphic development and distribution in the Sidingin field area.

The Cenomanian-Turonian Eagle Ford Group crops out along a broad belt in central and northern Texas. It has been suggested that this unit was a primary source for the 6 billion barrels of oil in East Texas Field. The unit was deposited during a major shoreline transgression. Although the unit may be viewed as representing a single “condensed” section, it displays considerable variability at several different scales. This study is based on detailed descriptions and geochemical analyses of Eagle Ford strata at two outcrop localities in central Texas, West Bouldin Creek (Austin) and Midway Park (Waco). The lower portion (South Bosque Member) of the measured sections of Eagle Ford at both localities is dominated by dark shales with a massive character. On detailed examination, these shales exhibit little bioturbation and are well-laminated. A few bentonites are evident in this portion of the section but are not as significant as in the overlying section. Above this interval, the Eagle Ford changes character dramatically. The upper section (Bouldin Member) is composed of a series of interbedded carbonate resistive layers and recessive shales with numerous bentonites. Geochemical analyses clearly establish differences in source rock quality between localities and within individual localities. If either locality was examined independently or as a representative sampling of the Eagle Ford there would be substantial differences in the estimated amounts of generated hydrocarbons as well as differences in the gas/oil ratios even if thermal maturity histories were considered comparable and differences in stratigraphic thickness were removed. Three basic organ ic-lithologic facies were determined at the Waco locality, based on the stratigraphy observed, the amount of organic carbon present, and expected products (oil and/or gas). At the Austin locality, two organic-lithologic facies were observed. An attempt is made to place the Austin outcrop in a sequence stratigraphic framework, although correlation to the Waco outcrop is ambiguous.

Abstract The Pitkin Formation is a Late Mississippian (Chesterian) high-energy marine oolitic-bioclastic limestone. The original mineralogy of Pitkin ooids varied across the Pitkin carbonate shelf. In the eastern part of the study area, originally aragonite ooids deposited in shoal and shoreface environments. These ooids are presently replaced by calcite and exhibit high Sr and low Mg concentrations. Originally calcite ooids in overlying lagoonal facies are composed of well-preserved, radial fabric. These ooids contain low Sr and high Mg values. Similar characteristics indicate that ooids in the central and western part of the study area were all originally calcite. An early marine nonferroan low-Mg calcite cement occurs as fibrous-to- bladed circumgranular crust, equant mosaic pore fill, and syntaxial overgrowth on echinoderm bioclasts. An extensive early dissolution event related to meteoric diagenesis dissolved aragonite and high- and low-Mg calcite components and created moldic and vuggy porosity. A late burial ferroan calcite occurs as mosaic and poikilotopic cements filling intergranular and moldic pores. Early marine and late burial calcite cementation eliminated virtually all porosity within Pitkin grainstones.