Showing papers in "AAPG Bulletin in 2015"

Pore types and pore-size distributions across thermal maturity, Eagle Ford Formation, southern Texas

Abstract: Pore types, pore size, and pore abundance vary systematically across thermal maturity in the Eagle Ford Formation, Maverick Basin, southern Texas. Scanning electron imaging of 20 samples from four wells is used to assess the complex response of pores to chemical and mechanical processes, entailing both destruction of primary porosity and generation of secondary pores. Primary mineral-associated pores are destroyed by compaction, cementation, and infill of secondary organic matter, whereas secondary pores are generated within organic matter (OM). Destruction of primary pores during early burial (to ∼0.5%) occurs by compaction of ductile detrital OM and clays and, to a lesser degree, as a result of cementation and infill of secondary OM. Larger pores are associated with coccolith debris. The dominant OM is spatially isolated detrital OM “stringers.” Porosity is volumetrically dominated (average 6.2%) by relatively large, mostly interparticle mineral-associated pores (median size 51.6 nm [0.000002 in.]; detection limit near 3–4 nm [0.00000012–0.00000015 in.]). At low maturity, porosity and pore size correlate directly with calcite abundance and inversely with OM volumes. At higher maturity, further destruction of primary pores occurs through cementation, secondary OM infill, and greater compaction. Mineral-associated pores are present at high-maturity ( ∼1.2%–1.3%), but are smaller (median size 30.2 nm [0.0000011 in.]) and less abundant (average of 2.5%) than at low maturity. A large portion of OM within high-maturity samples is diagenetic in origin and has pervaded into primary pore space, coating cement crystals, and filling intraparticle pores. Substantial mineral-associated porosity is locally present in samples where incursion of primary pore space by secondary OM has not occurred. Abundant secondary porosity is generated as OM matures into the wet-gas window. Porosity in most high-maturity samples is volumetrically dominated (average of 1.3%) by smaller, OM-hosted pores (median size 13.2 nm [0.00000051 in.]).

Geochemical and isotopic evolution of water produced from Middle Devonian Marcellus shale gas wells, Appalachian basin, Pennsylvania

Abstract: The number of Marcellus Shale gas wells drilled in the Appalachian basin has increased rapidly over the past decade, leading to increased interest in the highly saline water produced with the natural gas which must be recycled, treated, or injected into deep disposal wells. New geochemical and isotopic analyses of produced water for 3 time-series and 13 grab samples from Marcellus Shale gas wells in southwest and north central Pennsylvania (PA) are used to address the origin of the water and solutes produced over the long term (>12 months). The question of whether the produced water originated within the Marcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of and activity. These parameters indicate that the water originated in the Marcellus Shale, and can be more broadly used to trace water of Marcellus Shale origin. During the first 1–2 weeks of production, rapid increases in salinity and positive shifts in values were observed in the produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The values and relationships between Na, Cl, and Br provide evidence that the water produced after compositional stabilization is natural formation water, the salinity for which originated primarily from evaporatively concentrated paleoseawater. The rapid transition from injected water to chemically and isotopically distinct water while of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

The Barnett Shale: Compositional fractionation associated with intraformational petroleum migration, retention, and expulsion

Abstract: The Marathon 1 Mesquite well was drilled in Hamilton County, Texas, targeting the Barnett Shale with late oil window maturity. Combining a large suite of petrologic and high-resolution organic geochemical analyses on 120 core samples, we have been able to document qualitatively and quantitatively the effects of petroleum retention within and expulsion from five intervals within the Barnett Shale. Lithological heterogeneities control the composition and amount of retained fluids; the sorption of oil by solid organic matter is important in all intervals. Applying empirical formulas, we have been able to demonstrate not only that retention is primarily controlled by total organic carbon (TOC), but also that the “live” or “labile” component, rather than “dead” or “inert” carbon, constitutes the most active sorptive sites. Additional retention in the micropores provided by biogenic microcrystalline quartz (sponge spicules) accounts for the sweet spot defined by an “oil crossover” in the 9.14-m (30-ft) thick second interval. The fluorescing oil occurring in the axial chamber of the sponge spicules and that sorbed on organic particles are together enriched in saturated hydrocarbons, whereas the dispersed oil from the adjacent interval 3 is depleted in this compound class. Mass-balance calculations reveal that short-distance migration of petroleum into this “reservoir” interval (second) fractionates the generated oil into a higher quality oil by preferential retention in the order polar compounds > aromatic hydrocarbons > saturated hydrocarbons within the underlying organic matter and clay-rich third interval (source unit). Furthermore, molecular fractionation, i.e., a preferential expulsion of lower molecular weight hydrocarbons (n-alkanes) could be calculated. An additional practical result for source rock assessment is that corrected S2 (petroleum generated by pyrolysis) and TOC values should be calculated by combining Rock-Eval pyrolysis data on whole rocks and rocks following Soxhlet extraction. Using parameters based on unextracted rock only, the expulsion of petroleum is systematically overestimated and the degree of kerogen conversion is, therefore, concomitantly underestimated.

Feldspar dissolution, authigenic clays, and quartz cements in open and closed sandstone geochemical systems during diagenesis: Typical examples from two sags in Bohai Bay Basin, East China

Abstract: Feldspar dissolution and precipitation of clays and quartz cements are important diagenetic reactions affecting reservoir quality evolution in sandstones with detrital feldspars. We examined two sets of sandstone reservoirs to determine whether the sandstone diagenetic systems were open or closed to the mass transfer of products from feldspar dissolution and its impact on reservoir quality. One of the reservoirs is the Eocene fan delta sandstone buried 2.5–4.0 km (1.5–2.5 mi) below sea level (BSL) in the Gaoliu (GL) area of the Nanpu sag, and the other is the Eocene subaqueous fan sandstone buried 1.5–4.5 km (1–2.8 mi) BSL in the Shengtuo (ST) area of the Dongying sag. Both sandstones consist mainly of lithic arkoses and feldspathic litharenites, and have secondary porosity formed by dissolution of feldspars. In the GL sandstones, the absolute amounts of authigenic clays and quartz cements (generally 125°C [257°F]). The low abundance of authigenic clays and quartz cements, and low pore-water salinity indicate that much of the , , and released from leached K-feldspars were exported from the GL sandstone system. And the extensive feldspar dissolution enhanced much porosity and permeability. In contrast, the ST sandstones with secondary pores formed by feldspar dissolution generally contain authigenic clays (kaolinite and illite) and quartz cements with almost identical volume of secondary pores. Kaolinite dominates in the ST sandstones at shallower depth (3.1 km [2 mi] BSL) where temperature exceeds 125°C (257°F). The presence of abundant clays and quartz cements indicates that and released from leached feldspars were retained in the ST sandstone system. The dominance of authigenic illite at greater depth indicates that sufficient should have been retained within the sandstones for occurrence of illitization of kaolinite and feldspars. Secondary porosity in thin sections can be up to 3%, but little porosity ( The diagenetic difference between the GL and the ST sandstones can be interpreted by assessing pore-water evolution in these two areas. The current pore waters with low salinity and negative hydrogen isotopic compositions in the GL sandstone system indicate the significant impact of meteoric water, whereas the current pore waters with high salinity and the paleofluids with positive oxygen isotopic compositions in the ST sandstone system indicate little trace of meteoric water. Access of meteoric freshwater to the GL area probably occurred during the late Oligocene to Neogene through widely developed faults in the Paleogene and Neogene strata. The low-salinity water could have been responsible for flushing of solutes derived from feldspar dissolution. As such, diagenesis in the GL sandstones is considered to have occurred in an open geochemical system, whereas with limited faults and high water salinity, the ST sandstones acted as a closed geochemical system where precipitation of kaolinite, illite, and quartz cements occurred following dissolution of feldspars.

Characteristics of silty laminae in Zhangjiatan Shale of southeastern Ordos Basin, China: Implications for shale gas formation

Abstract: Shale oil and gas have been discovered in the lacustrine organic-rich Zhangjiatan Shale of the Upper Triassic Yanchang Formation, Ordos Basin, China. Core observations indicate abundant silty laminae in the producing shales. This study documents the stratigraphic distribution of silty laminae and their relationship with interlaminated clay laminae. The type, structure, and characteristics of pores and mineral composition of silty laminae were observed and analyzed through thin section and scanning electron microscopy, X-ray diffraction, low-pressure ![Formula][1] and ![Formula][2] adsorption, mercury porosimetry, and helium pycnometry. Results from silty laminae are compared with those of clayey laminae. The frequency and thickness of silty laminae vary over a wide range. The thickness ranges from 0.2 to 4 mm and is 1.5 mm on average; the frequency ranges from 4 to 32 laminae/m and is 23 laminae/m on average. The thickness percentage of silty laminae in the measured segments ranges from 6% to 17%. Silty laminae consist of quartz, feldspar, mixed-layer montmorillonite, and chlorite. In comparison to clayey laminae, non-clay detrital grains are larger, quartz and feldspar are more common, and clay minerals are less abundant. Pores in silty laminae are primary interparticle, dissolutional, intercrystalline, and microfracture types. Mesopores (2–50 nm in diameter) and macropores (50 nm–1 μm) are common, whereas, micropores ![Formula][3] are rare; the distribution of pore diameters is multimodal. However, microscopic pores with a diameter commonly smaller than 100 nm are common in clayey laminae. Thus, pore volume and surface area of micropores in silty laminae are less than those in the adjacent clayey laminae, and vice versa for meso- and macropores. The porosity of shales increases with the proportion of silty laminae in the shales. The silty laminae provide the storage space and flow conduit for oil and gas, and they play a significant role in the migration, accumulation, occurrence, and amount of gas in the shales. [1]: /embed/mml-math-1.gif [2]: /embed/mml-math-2.gif [3]: /embed/mml-math-3.gif

Organic matter pores and oil generation in the Tuscaloosa marine shale

Abstract: The Upper Cretaceous Tuscaloosa marine shale (TMS) is an oil play across central Louisiana and southwest Mississippi The lower TMS is characterized by relatively high log resistivity (>5 ohm-m) compared to the upper part, and this elevated resistivity zone (ERZ) has become the primary target zone This study is to investigate the cause of variation in log resistivity based on the data of petrography, mineralogy, and organic matter property and porosity The results suggest that log resistivity is not controlled by mineralogy or porosity; rather, it is associated with oil generation during organic matter maturation Total organic carbon (TOC) content, Rock-Eval free hydrocarbon yield (S1), and hydrogen index (HI) in the studied core increase with depth Porosity within organic matter (OM), measured by field-emission scanning electron microscopy (FE-SEM), is also higher within the ERZ The correlated variations among TOC content, S1 values, OM porosity, and log resistivity suggest that the higher log resistivity resulted from in situ oil generation and that the OM pores were generated during oil generation Thermal maturity varies little in the core; whereas the downward-increasing HI indicates an increasing abundance of oil-prone type II kerogen Higher OM porosity appears to be related to the greater proportion of type II kerogen in the ERZ The data set demonstrates that higher contents of TOC and oil-prone kerogen are the combined factors for higher oil generation, therefore, higher log resistivity in the ERZ The study provides a quantitative relationship between OM porosity and oil generation

The evolution of pore-scale fluid-saturation in low-permeability sandstone reservoirs

Abstract: In many tight-gas basins of the western United States distinguishing between productive and non-productive low-permeability sandstones, and predicting relative amounts of gas and water production is difficult. Comparison of gas shows, calculated water saturations, and saturation-height profiles between gas-productive and non-productive sandstones of equal reservoir quality all appear similar. Capillary pressure derived height functions are difficult to apply, and classic rock-typing procedures lack the predictive capability that is common to more traditional reservoirs. Basin reconstructions suggest the timing of petroleum charge and migration preceded maximum burial and uplift. This initial charge was likely a primary drainage displacement with reservoir porosity greater by a factor of 2-3 relative to values found today and permeability greater by 1-3 orders of magnitude. These reservoir systems became low-permeability following initial charge reflecting continued diagenesis throughout burial, subsequent uplift and erosion. With burial, decreasing pore volume caused water saturations and gas columns to increase. During uplift and erosion gas columns adjusted to changing structural configuration. In some cases this led to gas accumulations being leaked and spilled. In other cases, structural readjustment resulted in capillary imbibition and, in some cases, secondary (or higher order) drainage and imbibition. Within trapped accumulations, gas expansion upon uplift further increased gas columns. In cases where gas columns were spilled or within migration pathways imbibition led to residual or near-residual water saturations. Conventional formation evaluation is fundamentally rooted in concepts associated with primary drainage displacement. Tight-gas reservoirs that have experienced late uplift following an earlier phase of charge are unlikely to be characterized by primary drainage and are much more likely to be characterized by imbibition or secondary (or higher order) drainage and possibly imbibition. The hysteresis between primary drainage and imbibition or secondary (or higher order) drainage and imbibition in tight-gas reservoirs is significant and unlike many more traditional reservoirs does not tend to converge on a narrow range of values. Estimates of water saturation are scalar values and do not contain information that allows the saturation history and displacement direction to be deciphered. Recognition that reservoirs are unlikely to be in primary drainage equilibrium is a fundamental paradigm shift that impacts petroleum evaluation at all scales ranging from basin potential to completion decisions within a given well. Although this paper is written from the perspective of tight-gas petroleum systems, the principles are equally applicable to low-permeability oil reservoirs.

Feldspar dissolution-enhanced porosity in Paleoproterozoic shale reservoir facies from the Barney Creek Formation (McArthur Basin, Australia)

Abstract: The Paleoproterozoic Barney Creek Formation (BCF; McArthur Basin, Australia) is one of the oldest active hydrocarbon systems on Earth with oil and gas shows present within organic-rich intervals (up to 7 wt. % total organic carbon). We combine bulk geochemical analyses, pore-space characterization, and high-resolution electron imaging techniques to characterize the evolution of the BCF pore system with maturity. A thermal gradient from the pre-oil window (0.48% calc. ) to gas window (1.01% calc. ) shows a progressive change in pore networks with the loss of organic-hosted pores dominant in thermally immature samples to porosity increasingly associated with the mineral matrix with thermal maturity. Precipitation of fine-grained, high surface area cements reduced porosity within the oil window, whereas feldspar and dolomite dissolution and creation of secondary pores increased porosity within the gas window. The abundance of feldspar grains (up to 50%) provided a significant potential for secondary pore formation as well as a source of silica and clay cement. This study identifies a first-order linkage between the chemically reactive sediments that are key to the reservoir properties in the BCF and a provenance and/or weathering intensity conducive to supplying fine-grained, mineralogically immature sediments during deposition. These findings likely apply more broadly to other chemically immature mudrocks typical of Precambrian age sediments or Phanerozoic settings subject to limited chemical weathering.

A model describing flowback chemistry changes with time after Marcellus Shale hydraulic fracturing

Abstract: Between 2005 and 2014 in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to (7 to ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to () in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ∼10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%–0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ∼1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.

Geologic evolution of the Iraqi Zagros, and its influence on the distribution of hydrocarbons in the Kurdistan region

Abstract: Whereas the vast majority of discovered hydrocarbon reserves in Iraq reside in Cretaceous and Cenozoic reservoirs, numerous oil and gas fields have been discovered recently in deeper Jurassic and Triassic reservoirs in the Kurdistan region of Iraq. This study presents a Middle–Upper Jurassic thermal maturity map for the Kurdistan region of Iraq and demonstrates that regional first-order trends in Jurassic source rock maturity show a close correlation to the spatial distribution of oil gravities within the overlying Jurassic (and Cretaceous) reservoirs. This distribution is consistent with compartmentalization of the active source rock kitchens due to Zagros folding, resulting in relatively short-distance migration and charge of the anticlinal structures from the adjacent synclinal lows. The thermal maturity map confirms relatively low maturity over the Mosul high, where the Cretaceous and Cenozoic section overlying the source rock interval is relatively thin, and increasing maturity to the southeast as the thickness of the Cenozoic foredeep sediments increases toward the depocenter located in the southeastern Iraqi Zagros and the adjacent Iranian Zagros. The correlative trend in oil gravities is exemplified by the recent Jurassic discoveries: low to medium gravity oils (14–27° API) in Shaikan and Atrush to the northwest, light oil (39–47° API) in Mirawa and Bina Bawi, and gas condensate (55° API) in Miran West to the southeast. Understanding thermal maturity patterns and hydrocarbon fluid-type distributions will help to guide risk assessment for remaining prospectivity and future exploration drilling within the Kurdistan region of Iraq.

The discovery of the Barmer Basin, Rajasthan, India, and its petroleum geology

Abstract: The discovery of oil and gas in the Barmer Basin in northwest India was one of the more significant global discoveries in the decade 2001–2010. The basin’s presence was suspected from gravity and magnetic data in the late 1980s but not confirmed until 1999 from seismic and drilling. The basin is a lacustrine failed rift. Biostratigraphic data, however, indicate it was intermittently connected to marine waters via either the Cambay Basin, the Kutch Basin, or across the Devikot high, temporarily forming a large, shallow estuary. At least six major tectono-stratigraphic events have caused relative lake level falls and translation of clastic reservoirs basinward. Upward of 6 km (∼20,000 ft) of Cenozoic and Mesozoic sedimentary rocks have been preserved. Prolific source rocks occur from the Mesozoic through Eocene strata. Tectonically, the basin is divided into a northern and a southern province. The north province continues to undergo inversion and erosion, and has not been buried as deeply as the south. Kinetics of the major source facies in the north are substantially different from those in the south, as well as the present-day and paleo-heat flow. These differences have made the northern part of the basin predominantly an oil province and the southern part a mixed oil and gas province. The prolific Paleocene Fatehgarh Formation contains the bulk of the 7.3 billion barrels of stock tank oil in place (STOIP) identified to date, but other reservoirs from the Mesozoic to the late Cenozoic are common and may yield significant future resource additions.

Petroleum generation kinetics: Single versus multiple heating-ramp open-system pyrolysis

Abstract: Some recent publications promote one-run, open-system pyrolysis experiments using a single heating rate (ramp) and fixed frequency factor to determine the petroleum generation kinetics of source-rock samples because, compared to multiple-ramp experiments, the method is faster, less expensive, and presumably yields similar results. Some one-ramp pyrolysis experiments yield kinetic results similar to those from multiple-ramp experiments. However, our data for 52 worldwide source rocks containing types I, II, IIS, II/III, and III kerogen illustrate that one-ramp kinetics introduce the potential for significant error that can be avoided by using high-quality kinetic measurements and multiple-ramp experiments in which the frequency factor is optimized by the kinetic software rather than fixed at some universal value. The data show that kinetic modeling based on a discrete activation energy distribution and three different pyrolysis temperature ramps closely approximates that determined from additional runs, provided the three ramps span an appropriate range of heating rates. For some source rocks containing well-preserved kerogen and having narrow activation energy distributions, both single- and multiple-ramp discrete models are insufficient, and nucleation-growth models are necessary. Instrument design, thermocouple size or orientation, and sample weight likely influence the acceptable upper limit of pyrolysis heating rate. Caution is needed for ramps of 30–50°C/min, which can cause temperature errors due to impaired heat transfer between the oven, sample, and thermocouple. Compound volatility may inhibit pyrolyzate yield at the lowest heating rates, depending on the effectiveness of the gas sweep. We recommend at least three pyrolysis ramps that span at least a 20-fold variation of comparatively lower rates, such as 1, 5, and 25°C/min. The product of heating rate and sample size should not exceed ∼100 mg °C/min. Our results do not address the more fundamental questions of whether kinetic models based on multiple-ramp open-system pyrolysis are mechanistically appropriate for use in basin simulators or whether petroleum migration through the kerogen network, rather than cracking of organic matter, represents the rate-limiting step in expulsion.

Cenozoic paleogeography of the Andean foreland and retroarc hinterland of Colombia

Abstract: New biostratigraphic zonations, core descriptions, sandstone petrography, facies analysis, and seismic information are compared with published detrital and bedrock geo- and thermochronology to build a Cenozoic paleogeographic reconstruction of the Andean retroarc region of Colombia, encompassing the ancestral Central Cordillera, Middle Magdalena Valley, Eastern Cordillera, and Llanos basin. We identify uplifted sediment source areas, provenance domains, depositional environments, and thickness changes to propose a refined paleogeographic evolution of eastern Colombia. We conclude that Cenozoic evolution of the northernmost Andes includes (1) a period of contractional deformation focused in the Central Cordillera and Middle Magdalena Valley that may have started by the Late Cretaceous, although thermochronological data points to maximum shortening and exhumation during the late Paleocene; (2) a period of slower deformation rates or even tectonic quiescence during the middle Eocene; and (3) a renewed phase of contractional deformation from the late Eocene to the Pleistocene/Holocene expressed in provenance, bedrock thermochronology, and increased subsidence rates in the Llanos foreland. The sedimentary response in the Llanos foreland basin is controlled by source area proximity, exhumation and shortening rates, relationships between accommodation and sediment supply, as well as potential paleoclimate forcing. This new reconstruction changes the picture of Cenozoic basin evolution offered by previous reconstructions, providing an updated chronology of deformation, which is tied to a more precise understanding of basin evolution.

Cretaceous volcanic reservoirs and their exploration in the Songliao Basin, northeast China

Abstract: Major reservoirs in the Songliao Basin (SB) are composed of volcanic rocks below 3000 m (9843 ft) of buried depth. Gas accumulations are mostly found in the buried volcanic highs, which in general correspond to paleovolcanic centers. Porosity in the volcanic rocks depends on both primary and secondary processes. The best porosity is preferentially developed in a proximal facies near the central part of each volcanic edifice. Porosity and permeability decrease with depth of burial for both volcanic and nonvolcanic sections, but their porosity-depth trends differ. Lava and welded ignimbrite slowly lose porosity with burial depth because they solidified by cooling, and their groundmasses are poor in quartz and calcite precipitation, thus preserving porous space. In contrast, the associated sandstone, conglomerate, tuff, and tuffite are more sensitive to overburden pressure, suffering more intense compaction and cementation. As a result, porosity and permeability of lava and ignimbrite exceed that of the other rocks, and thus, they are the best reservoir rocks below burial depths of ca. 3000 m (9843 ft) in the SB. The paleovolcanic domes are rich in both lava rocks and fractures of diverse origin, and the topographic highs provide favorable locations for gas migration and accumulation.

Geological and hydrological controls on water coproduced with coalbed methane in Liulin, eastern Ordos basin, China

Abstract: Significant amounts () of water are currently being extracted from coalbed methane (CBM) wells in Permian–Carboniferous coal in the Liulin area of the eastern Ordos basin, China. Waters coproduced with CBM have common chemical characteristics that can be an important exploration tool because they relate to the coal depositional environment and hydrodynamic maturation of groundwater and can be used to guide CBM development strategies. The CBM production targets of the No. 3 and 4 coal seams from sandstone in the Shanxi Formation and No. 8, 9, and 10 coal seams in the karst of the Taiyuan Formation were deposited in fluvial-deltaic and epicontinental-sea environments, respectively. This paper combines CBM geology, hydrogeology, CBM recovery, and laboratory data to define mechanisms of CBM preservation including the important influence of groundwater. Relevant indices include fluid inclusions as an indicator of the hydraulic connection between the coal seam reservoir and the overlaying strata and the ensemble characteristics of total dissolved solids (TDS) contents of water, water production rates, and reservoir temperatures as an indication of the current hydraulic connection. The TDS contents of waters from the No. 3 and 4 and No. 9 and 10 coal seams are double those from the subjacent karst No. 8 coal seam, indicating the important control of fast flow in karst. Low-salinity fluid inclusions from the roof of the subjacent-karst No. 8 coal seam also indicate an enduring hydraulic connection with overlaying strata during its burial history. Relatively low current temperatures in the No. 8 (subjacent-karst) coal seam also infer a strong hydraulic connection and active flow regime. Deuterium concentrations are elevated in the mudstone-bounded No. 9 and 10 coal seams, further confirming low rates of fluid transmission. The gas contents of coal seams from the Taiyuan Formation are higher than those from the sandstone-bounded coal seams in Shanxi Formation, also correlating with low rates of water transmission and low permeability. Conceptual models for these fluvial-deltaic and epicontinental-sea environments that are consistent with geology, gas content, and gas and water production rate histories are of gas-pressure sealing for the Shanxi Formation and hydrostatic-pressure sealing for the Taiyuan Formation. These results confirm the important controls of hydrogeological conditions on the preservation of CBM and the utility of hydrogeological indicators in prospecting for CBM.

Continental carbonates as a hydrocarbon reservoir, an analog case study from the travertine of Saturnia, Italy

Abstract: The Pleistocene Saturnia travertine (central Italy) represents a possible analog of the pre-salt continental carbonate reservoirs discovered in the Santos and other basins in the South Atlantic margin of Brazil. Two subhorizontal travertine tabular bodies, several tens of meters thick and extending over an area of (), have been studied in two quarries. Facies variations and associated petrophysical properties were reconstructed applying a multidisciplinary approach. The Saturnia travertine, formed from a warm water spring, is composed of various stacked carbonate banks, separated by subaerial erosive phases and paleosols. The lacustrine tabular bodies, terraces, and sills are made of crystalline crust, shrub, pisoid, paper-thin raft, coated bubble, reed, and lithoclast-breccia facies. The (from +4‰ to +8‰) supports an interpreted volcanic mantle source, whereas, the (from −9‰ to −5‰) is in agreement with warm meteoric waters. The ratio isotopic signature indicates a carbonate from dissolution of deep-seated carbonates. The facies reservoir properties were studied via porosity and permeability analysis of plugs, three-dimensional x-ray computer tomography, as well as image analysis on microscale under thin section and macroscale on large rock slabs to define various porosity indices. A strong heterogeneity of the petrophysical properties and variable connectivity were observed (porosity from 4% to 30% and permeability up to hundreds of md), but no compartmentalization of the carbonate bodies is present.

Depositional processes and impact on reservoir quality in deepwater Paleogene reservoirs, US Gulf of Mexico

Abstract: Reservoir deliverability is a critical risk for deepwater Paleogene reservoirs in the Gulf of Mexico. Permeability can vary two orders of magnitude (1s to 100s of md) for a given porosity within a single lithofacies. The objective of this paper is to frame reservoir quality within the architectural elements of submarine gravity flows in a deepwater Paleogene field. Approximately 380 m (1246 ft) of core was described from a lower and upper reservoir, and core descriptions were integrated with routine core analysis, petrography, and laser grain size analysis data. We distinguished specific rock property suites, textural, and compositional characteristics for channel, lobe, and lobe margin depositional environments. Channel architectural elements have the best reservoir quality because they are generally relatively coarser-grained and have a relatively low abundance of silt-sized particles (average 24%) and ductile grains (average 17%) dispersed as framework grains. Lobe architectural elements in the lower reservoir display moderate reservoir quality, and are composed of fine- to very fine-grained sandstone, with an average of 34% silt and 18% ductile grains. Upper reservoir lobes contain more silt (average 40%) and ductile grains (average 29%), and poorer reservoir quality. Reservoir quality is overall poor in the lobe margins where silt-sized particles and ductile grains are most abundant. The observed textural and compositional differences from the channel, lobe, to lobe margin environments are the result of grain segregations during transport within submarine gravity flows. As a best practice, reservoir quality should be examined in a depositional environment context.

Electrical and fluid flow properties of carbonate microporosity types from multiscale digital image analysis and mercury injection

Abstract: Electrical and fluid flow properties of porous media are directly related to the morphology of pores and the connectivity of the pore network. Both are closely linked to the amount and type of intrinsic microporosity in carbonate rocks, which is not resolved by conventional techniques. Broad-ion-beam (BIB) milling produces high-quality true-two-dimensional cross sections for scanning electron microscopy (SEM) and enables accurate quantification of carbonate microporosity for the first time. The combination of BIB-SEM mosaics with optical micrographs yields a multiscale digital image analysis (MsDIA) spanning six orders of magnitude. In this paper, the pore structures of 12 different carbonate rock samples from various rock types are quantified using MsDIA. Mercury injection capillary pressure measurements are used to assess pore-throat properties. The quantified pore-structure parameters are correlated with plug measurements of electrical resistivity and permeability. Results indicate that petrophysical properties are closely linked to the type of microporosity, which is distinctive for a certain rock type. Rock types with crystalline microporosity, such as mudstone and dolomite, generally show good connectivity, in which the size of the pore-network determines if the rock favors either hydraulic or electric flow. Rock types with intercement or micromoldic microporosity, such as bindstone and travertine, show variations in connectivity due to layering and moldic micropores of biological origin. Furthermore, pore-size distributions (PSD) follow a power law in all samples, despite their depositional and diagenetic differences. The slope of the PSD correlates with the electric properties, in which samples with a steeper slope show lower cementation factors. The linearity of the power law distribution enables predictions of pore populations outside the investigated length scales.

U.S. Geological Survey 2013 assessment of undiscovered resources in the Bakken and Three Forks Formations of the U.S. Williston Basin Province

Abstract: The Upper Devonian Three Forks and Upper Devonian to Lower Mississippian Bakken Formations comprise a major United States continuous oil resource. Current exploitation of oil is from horizontal drilling and hydraulic fracturing of the Middle Member of the Bakken and upper Three Forks, with ongoing exploration of the lower Three Forks, and the Upper, Lower, and Pronghorn Members of the Bakken Formation. In 2008, the U.S. Geological Survey (USGS) estimated a mean of 3.65 billion bbl of undiscovered, technically recoverable oil resource within the Bakken Formation. The USGS recently reassessed the Bakken Formation, which included an assessment of the underlying Three Forks Formation. The Pronghorn Member of the Bakken Formation, where present, was included as part of the Three Forks assessment due to probable fluid communication between reservoirs. For the Bakken Formation, five continuous and one conventional assessment units (AUs) were defined. These AUs are modified from the 2008 AU boundaries to incorporate expanded geologic and production information. The Three Forks Formation was defined with one continuous and one conventional AU. Within the continuous AUs, optimal regions of hydrocarbon recovery, or “sweet spots,” were delineated and estimated ultimate recoveries were calculated for each continuous AU. Resulting undiscovered, technically recoverable resource estimates were 3.65 billion bbl for the five Bakken continuous oil AUs and 3.73 billion bbl for the Three Forks Continuous Oil AU, generating a total mean resource estimate of 7.38 billion bbl. The two conventional AUs are hypothetical and represent a negligible component of the total estimated resource (8 million barrels of oil).

Distribution of total dissolved solids in McMurray Formation water in the Athabasca oil sands region, Alberta, Canada: Implications for regional hydrogeology and resource development

Abstract: Total dissolved solids (TDS) concentrations of 258 Lower Cretaceous McMurray Formation water samples in the Athabasca oil sands region (54 to 58°N and 110 to 114°W) were mapped using published data from recent government reports and environmental impact assessments. McMurray Formation waters varied from nonsaline (240 mg/L) to brine (279,000 mg/L) with a regional trend of high salinity water approximately following the partial dissolution front of the Devonian Prairie Evaporite Formation. The simplest hydrogeological explanation for the observed formation water salinity data is that Devonian aquifers are locally connected to the McMurray Formation via conduits in the sub-Cretaceous karst system in the region overlying the partial dissolution front of the Prairie Evaporite Formation. The driving force for upward formation water flow is provided by the Pleistocene glaciation events that reversed the regional Devonian flow system over the past 2 m.y. in the Athabasca region. This study demonstrates that a detailed approach to hydrogeological assessment is required to elucidate TDS concentrations in McMurray Formation waters at an individual lease-area scale. The observed heterogeneity in formation water TDS and the potential for present day upward flow has implications for both mining and in situ oil sands resource development.

Shelf-edge trajectories and stratal stacking patterns: Their sequence-stratigraphic significance and relation to styles of deep-water sedimentation and amount of deep-water sandstone

Abstract: Using a seismic database from the Qiongdongnan Basin in the South China Sea, this study demonstrates that shelf-edge trajectories and stratal stacking patterns are reliable, but understated, predictors of deep-water sedimentation styles and volumes of deep-water sand deposits, assisting greatly in locating sand-rich environments and in developing a more predictive and dynamic stratigraphy. Three main types of shelf-edge trajectories and their associated stratal stacking patterns were recognized: (1) flat to slightly falling trajectories with negative trajectory angles () (−2° to 0°) and negative shelf-edge aggradation to progradation ratios () (−0.04 to 0) and associated progradational and downstepping stacking patterns with low clinoform relief () (150–550 m [492–1804 ft]) and negative differential sedimentation on the shelf and basin () (−0.6 to 0); (2) slightly rising trajectories with moderate (0°–2°) and medium (0–0.04), and associated progradational and aggradational stacking patterns with intermediate (250–400 m [820–1312 ft]) and intermediate (0–0.6); and (3) steeply rising trajectories with high (2°–6°) and high (0.04–0.10) and associated dominantly aggradational stacking patterns with high (350–650 m [1148–2132 ft]) and high (1–2). Each trajectory regime represents a specific stratal stacking patterns, providing new tools to define a model-independent methodology for sequence stratigraphy. Flat to slightly falling shelf-edge trajectories and progradational and downstepping stacking patterns are empirically related to large-scale, sand-rich gravity flows and associated bigger and thicker sand-rich submarine fan systems. Slightly rising shelf-edge trajectories and progradational and aggradational stacking patterns are associated with mixed sand/mud gravity flows and moderate-scale slope-sand deposits. Steeply rising shelf-edge trajectories and dominantly aggradational stacking patterns are fronted by large-scale mass-wasting processes and associated areally extensive mass-transport systems. Therefore, given a constant sediment supply, then , , , and are all proportional to intensity of mass-wasting processes and to amounts of mass-transport deposits, and are inversely proportional to the intensity of sand-rich gravity flows and to amounts of deep-water sandstone. These relationships can be employed to relate quantitative characteristics of shelf-edge trajectories and stratal stacking patterns to deep-water sedimentation styles.

Kinematic restoration of contractional basement structures using thermokinematic models: A key tool for petroleum system modeling

Abstract: In this paper, we demonstrate a workflow for constructing kinematic restorations in complex foothill areas devoid of growth strata and other indicators for the chronology of deformation. Our initial reconstructions utilize thermochronometric data, a well-documented structural geometry, and a first-order conversion of exhumation rates into tectonic rates. We then utilize models obtained from the new in-house–developed software FetKin to build a first version of the thermokinematic restoration. The FetKin approach is geared primarily toward testing and further calibration and refinement of the kinematic restoration, based on the extent to which the model result agrees with thermochronometric data from the study area in the form of both discrete ages and inverse-modeled time–temperature envelopes. This analysis also provides rates of shortening and time–temperature paths throughout the model space that can be used to make first-order predictions of when different source rocks entered the oil window. These capabilities are demonstrated in a pilot case study along a cross section in the Colombian Eastern Cordillera. The improved confidence in the reconstruction that this technique provides allows us to show increasing shortening rates in this part of the Andes during the Neogene reaching up to 5 mm/yr (0.20 in./yr) by the Pliocene, and constrain the timing of generation from the most important oil kitchens for the Eastern Cordillera-Llanos basin petroleum system. This approach, therefore, proves to be a useful method for creating high-resolution and high-fidelity kinematic restorations.

Permeability characterization of natural compaction bands using core flooding experiments and three-dimensional image-based analysis: Comparing and contrasting the results from two different methods

Abstract: We measured the permeability of 30 samples extracted from 6 sets of compaction bands and the adjacent host rocks of the Jurassic aeolian Aztec Sandstone exposed in the Valley of Fire State Park in Nevada using core flooding experiments. The results show that the permeability within the high-angle compaction bands (three sets) is consistently three orders of magnitude lower than that of the host rocks. For the bed-parallel compaction bands, the measured permeability reduction is about half an order to three orders of magnitude for two sets of bands, and there is no detected permeability reduction for the samples from one set. For the samples that show permeability reduction within high-angle and bed-parallel compaction bands, the results are generally consistent with the data estimated from two-dimensional segmented image analyses in previous studies. Permeability of the samples used in the laboratory experiments was also obtained numerically based on three-dimensional tomographic images scanned from micro-samples and lattice-Boltzmann flow simulations. In addition, backscatter electron images (BEI) and energy dispersive spectroscopy images (EDSI) of thin sections were used to estimate the clay content inside and outside the bands. Large differences exist between the lab-based and image-based permeability and porosity measurements of compaction bands and host rocks. Possible factors causing these differences are different sample sizes and heterogeneities within the host rocks, calibration on the image segmentation, and incomplete characterization of clay minerals and fines migration during lab-based experiments. Given the wide range of permeability reductions within compaction bands of different orientations by different investigators, their impact on fluid flow should be evaluated case by case, one should consider their dimensions and distributions.

Developing a model discrete fracture network, drilling, and enhanced oil recovery strategy in an unconventional naturally fractured reservoir using integrated field, image log, and three-dimensional seismic data

Abstract: In this study, we develop a model discrete fracture network (DFN) for the unconventional, naturally fractured Tensleep Sandstone oil reservoir at Teapot Dome, Wyoming. Reservoir characterization is based on three-dimensional (3D) seismic data, fracture image logs from Teapot Dome, and field observations of the Tensleep exposure in the Alcova anticline and Fremont Canyon areas. Image logs reveal that the dominant reservoir fracture set trends parallel to the present-day maximum horizontal compressive stress () inferred from drilling induced fractures. Analog field studies of the Alcova anticline and Fremont Canyon suggest fracture heights and lengths are power-law distributed, while the fracture spacing distribution is best described as log-normal. Image-log–derived fracture apertures are also log-normally distributed. These properties are incorporated into a model DFN. We assume subseismic folds, faults, and fracture zones control fracture intensity distribution and use composite 3D seismic attributes to locate subtle changes in seismic response interpreted to result from subseismic structure. Directional curvature defines aperture-opening strain normal to the dominant reservoir fracture set. Seismic attributes are scaled and combined to control fracture intensity variations in the model. Grid-cell porosity and permeability distributions derived from the DFN suggest the presence of northeast–southwest-trending reservoir compartments. We suggest that enhanced oil recovery operations may be optimized using lateral injection and production wells oriented along interpreted compartment boundaries at high angles to . This combination of injection and production laterals could help maximize storage and hydrocarbon recovery in depleted reservoirs and in down-dip residual oil zones.

Stratigraphic evolution of intraslope minibasins: Insights from surface-based model

Abstract: Although numerous case studies exist to illustrate the large-scale stratigraphic architecture of salt-withdrawal minibasins, there is no clear understanding of how stratal patterns emerge as a function of the interplay between basin subsidence and sedimentation. Here we present a simple model of mass balance in minibasin sedimentation that focuses on the interaction between long-term sediment supply and basin-wide subsidence rate. The model calculates the sediment flux in three dimensions assuming a simplified basin and deposit geometry. The main model output is a cross section that captures the large-scale stratigraphic patterns. This architecture is determined by the relative movement of the stratal terminations along the basin margin: consecutive pinchout points can (1) be stationary, (2) move toward the basin edge (onlap), or (3) move toward the basin center (offlap). The direction and magnitude of this movement depend on the balance between the volume made available through subsidence, calculated only over the area of the previous deposit, and the volume needed to accommodate all the sediment that comes into the basin. Cycles of increasing-to-decreasing sediment supply result in stratigraphic sequences with an onlapping lower part and offlapping upper part. If the sediment input curve is more similar to a step function, stratigraphic sequences only consist of an onlapping sediment package, with no offlap at the top. Modeling two linked basins in which deposition takes place during ongoing subsidence shows that conventional static fill-and-spill models cannot correctly capture the age relationships between basin fills. In general, lower sediment input rates and periods of sediment bypass result in sand-poor convergent stratal patterns, and episodic but high volumetric sedimentation rates lead to well-defined onlap with an increased probability of high sand content.

Characterization of the micropore systems in high-rank coal reservoirs of the southern Sichuan Basin, China

Abstract: To gain a better understanding of the characteristics of micropore systems in high-rank coal reservoirs, 51 coal core samples collected from 16 wells were examined by maceral analysis, proximate analysis, scanning electron microscopy observation, low-temperature nitrogen gas adsorption, and nuclear magnetic resonance (NMR). The results show that pores in coals can be divided into plant tissue hole, blowhole, dissolved pore, and intercrystalline pore, and they have three structure shapes: open pore, semiclosed pore, and “ink bottle” pore. The total specific surface area (Brunauer-Emmet-Teller [BET]) ranges from 0.611 to (7 to ), averaged at . The total pore volume (Barrett-Joyner-Halenda model [BJH]) ranges from 0.0018 to (0.0001 to ) with an average of , and it shows a good positive relationship with . The adsorption amount shows a good positive relationship with the total and . The average pore size ranges from 5.775 to 17.842 nm. Pores that are smaller than 5 nm make up the main contribution to the pore surface area, and those larger than 10 nm contribute greatly to the pore volume. Inertinite-rich coals have higher total specific surface area, pore volume, pore size, and adsorption capacity than those in vitrinite-rich coals. Lopingian coal reservoirs are characterized by low porosity and extremely low permeability obtained from NMR tests, and the permeability has a positive correlation with the porosity. The average permeability of inertinite is almost twice that of vitrinite .

Factors controlling petroleum accumulation and leakage in overpressured reservoirs

Abstract: This paper reviews the hydrocarbon-retaining properties of overpressured reservoirs and discusses the mechanisms for petroleum accumulation, preservation and loss in overpressured reservoirs, and the factors controlling hydrocarbon column heights in overpressured traps. Four types of overpressured traps (filled, underfilled, unfilled, and drained) are recognized. The diversities in petroleum-bearing properties reflect the complexities of petroleum accumulation and leakage in overpressured reservoirs. Forced top seal fracturing, frictional failure along preexisting faults, and capillary leakage are the major mechanisms for petroleum loss from overpressured reservoirs. The hydrocarbon retention capacities of overpressured traps are controlled by three groups of factors: (1) factors related to minimum horizontal stress (tectonic extension or compression, stress regimes, and basin scale and localized pressure–stress coupling); (2) factors related to the magnitudes of water-phase pressure relative to seal fracture pressure (the depth to trap crest, vertical and/or lateral overpressure transfer, mechanisms of overpressure generation); and (3) factors related to the geomechanical properties of top seals or sealing faults (the tensile strength and brittleness of the seals, the natures and structures of fault zones). Commercial petroleum accumulations may be preserved in reservoirs with pressure coefficients greater than 2.0 and pore pressure/vertical stress ratios greater than 0.9 (up to 0.97). The widely quoted assumption that the fracture pressure is 80%–90% of the overburden pressure and hydrofracturing occurs when the pore pressure reaches 85% of the overburden pressure significantly underestimates the maximum sustainable overpressures, and thus, potentially the hydrocarbon-retention capacities, especially in deeply buried traps. Lateral and/or vertical water-phase overpressure transfer from deeper successions plays an important role in the formation of unfilled and drained overpressured traps. Traps in hydrocarbon generation-induced overpressured systems have greater exploration potential than traps in disequilibrium compaction-induced overpressured systems with similar overpressure magnitude.

Stratigraphic architecture of fluvial deposits from borehole images, spectral-gamma-ray response, and outcrop analogs, Piceance Basin, Colorado

Abstract: Lithofacies, architectural-element abundance, and estimates of dune-bedform height and channel sinuosity from borehole images (BHIs) and well-exposed outcrops allow for an expanded interpretation of the fluvial stratigraphic architecture of the Upper Cretaceous Williams Fork Formation. Sedimentologic and stratigraphic data from outcrops and detailed core descriptions of the Williams Fork Formation, Piceance Basin, Colorado, were used to compare attributes of fluvial architectural elements to BHI characteristics and spectral-gamma-ray (SGR) log motifs. Results show a distinct set of criteria based on BHIs that aid in the interpretation of lithofacies and fluvial reservoir architecture. In contrast, a practical correlation does not exist between outcrop- and core-derived SGR log motifs or thorium and potassium abundances and fluvial lithofacies or architectural elements. Four electrofacies based on BHI characteristics (e.g., dip type, dip pattern, and color scheme) represent the most common fluvial lithofacies and are identified through comparison of paired, calibrated BHIs and core. Cross-bed-set thickness values from BHIs are used to calculate dune height as a proxy for flow energy. The lower and middle Williams Fork Formation represent low-energy meandering and higher energy braided systems, respectively, as evident by changes in channel sinuosity and architectural-element type. The upper Williams Fork Formation is divided into two intervals based on lithofacies, architectural elements, channel sinuosity, and net-to-gross ratio. The subdivision for the upper Williams Fork Formation represents a change from a lower energy, meandering fluvial system to a higher energy, lower sinuosity braided system as related to changes in accommodation through time.

Allochthonous salt initiation and advance in the northern Flinders and eastern Willouran ranges, South Australia: Using outcrops to test subsurface-based models from the northern Gulf of Mexico

Abstract: The northern Flinders Ranges and eastern Willouran Ranges, South Australia, expose Neoproterozoic salt diapirs, salt sheets, and associated growth strata that provide a natural laboratory for testing and refining models of allochthonous salt initiation and emplacement. The diapiric Callanna Group (∼850–800 Ma) comprises a lithologically diverse assemblage of brecciated rocks that were originally interbedded with evaporites that are now absent. Using stereonet analysis to derive three-dimensional information from two-dimensional outcrops of stratal geometries flanking salt diapirs and beneath salt sheets, we evaluate 10 examples of the transition from steep diapirs to salt sheets, 3 of ramp-to-flat geometries, and 2 of flat-to-ramp transitions. Stratal geometries adjacent to feeder diapirs range from a minibasin-scale megaflap to halokinetic drape folds to high-angle truncations and appear to have no relationship to subsequent allochthonous salt development. In all cases, the transition from steep diapirs to salt sheets is abrupt and involved piston-like breakthrough of thin roof strata, which permitted salt to flow laterally. We suggest two models to explain the transition from steep diapirs to subhorizontal salt: (1) salt-top breakout, where salt rise occurs inboard of the salt flank, thereby preserving part of the roof strata beneath the sheet; and (2) salt-edge breakout, where rise occurs at the edge of the diapir with no roof preservation. Lateral emplacement of salt sheets is dependent on the interplay between the rate of salt supply to the front of the sheet and the sediment-accumulation rate. When the ratio of salt-supply rate to sediment-accumulation rate is high to moderate, thrust advance produces base-salt flats and truncation ramps, respectively. Halokinetic folds are absent because the thrust emerges at the base of the sea-floor scarp and mass-transport complexes are rare as a result of relatively low scarp relief. If the ratio is low, pinned inflation leads to drape folding of the top salt and cover into a fold ramp, with occasional slumping of the sheet and its roof and further breakout on thrust or reverse faults. In the shallow-water depositional environments of South Australia, lateral emplacement of salt sheets occurred through some combination of thrust advance, extrusive advance, and open-toed advance, with no evidence for subsalt thrust imbricates, shear zones, or continuous rubble zones. In deep-water environments, such as the northern Gulf of Mexico, thrust imbricates and rubble zones, which represent slumped carapace, are more common. The presence of slumped carapace is caused primarily by higher topographic relief related to thicker hemipelagic roofs, a lack of dissolution, and gravity-driven transport of overburden strata to the toes of large canopies.