ALBERT

Description: 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.

Description: In Colombia, palynology has been widely used as a biostratigraphic tool in oil exploration over the last two decades and, as a result of these efforts, an understanding of the chronostratigraphic range of thousands of palynomorph species is now available. Furthermore, because of their relative resistance to physical and chemical degradation, palynomorphs can often survive several tectonic-erosive cycles, allowing them to be used as unique tracers of long-term sedimentological changes. In this work, we use the palynological record from wells and outcrops in the Llanos foothills and the Llanos basin of Colombia to establish the intensity of Cenozoic reworking and its relationship to the tectonic evolution of the Colombian Andes. Using this approach, we were able to discern several tectonic episodes associated with the uplift of the Eastern Cordillera. We documented three periods of either faster erosion in the hinterland or more widespread areas being eroded in the catchment areas (late Paleocene–early Eocene, early to mid Miocene and Pliocene) and two periods of tectonic quiescence (mid-Eocene and mid–late Miocene). These periods correlate well with the deposition of different elements of the petroleum systems in the Llanos basin of Colombia (seals and reservoirs).

Description: Physical and geochemical characteristics of produced petroleum from the central region of the Llanos basin, Colombia, were analyzed to understand the petroleum charge history and alteration processes. Petroleum properties in the study area are the result of the complex charge history of the oil fields. The amount of gas in fluids is controlled by the migration distance from the late or, possibly, the current generation kitchen located beneath the foothill deformation zone. Gas influx decreases toward the foreland domain, as indicated by lower values of the gas–oil ratio and saturation pressure. The API gravity of the oil samples is mainly controlled by the intensity of biodegradation. Marine-sourced oils accumulated in shallow reservoirs of the foreland prior to the onset of Andean deformation. Those fluids were subjected to different levels of biodegradation, depending on the time they remained at reservoir temperatures lower than 80°C (176°F) and before being buried to their maximum depth. Geochemical data suggest multiple charge pulses from different source kitchens of two main types of source rocks, as well as different biodegradation levels. The proposed petroleum charge and alteration model allows prediction of the temperature history of a reservoir and the most likely physical properties of the petroleum at a specific location. The model can be used as an exploration tool to assess the risk of charge prior to drilling in unexplored areas of the basin.

Description: The Llanos basin, located in the eastern region of Colombia, northwestern South America, is an Andean foreland basin between the Eastern Cordillera (Colombian Andes) and the Guyana Precambrian shield. The basin is the latest stage of a complex multiphase evolution that began in the Paleozoic at the latest. A Paleozoic–Pleistocene basin evolution model is presented based on a regional, two-dimensional, industry seismic data set and well-log observations for the southern part of the basin. Five tectono-stratigraphic sequences were identified: (1) lower Paleozoic depocenters preserved along inverted Neoproterozoic basement blocks; (2) an upper Paleozoic marine sequence folded and faulted in the late Paleozoic during assembly of Pangea; (3) Upper Cretaceous–Paleocene shallow marine sediments deposited in a distal foreland basin related to uplift of the Western and Central Cordilleras of Colombia, the sequence pinches out against a Paleozoic hinge or foreland bulge area; (4) an Eocene–Miocene foreland basin related to uplift of the Eastern Cordillera resulting in a wedge geometry; and (5) Pliocene–Pleistocene fluvial deltaic rocks overfilling the foreland basin. Reactivation of Paleozoic structures occurs at the top of this sequence with the development of anticlinal structures. Present-day stress fields indicate that subduction of the Nazca plate beneath South America may be responsible for reactivation of Paleozoic structures. Inversion of north–south structures with the Neoproterozoic basement is interpreted to be responsible for the Paleozoic and Pleistocene deformation, whereas Cenozoic deformation is related to the two main stages of foreland development of the basin. To the east, where the Paleoproterozoic basement is present, no deformation is interpreted.

Description: In the present study, stratigraphic data from cores and outcrop sections are integrated with data on thermal maturity, organic facies, and thermochronometric information to reconstruct the tectonic and associated petroleum system evolution of the eastern foothills thrust belt along the Colombian Eastern Cordillera, one of the most prolific hydrocarbon provinces in northern South America. Sedimentary and tectonic burial of the foreland autochthon caused maturation of the Coniacian to Santonian shallow marine Chipaque Formation, resulting in successive and diachronous episodes of hydrocarbon migration and trapping. One-dimensional and two-dimensional maturation modeling indicates that oil generation from the Chipaque Formation began at the Paleocene-Eocene boundary (55 Ma) in the southern parts of what is now the Eastern Cordillera and progressed to the north. By the late Oligocene, tectonic inversion of the Eastern Cordillera exhumed most of these kitchens, terminating the oil generation from the Chipaque Formation. Kitchens migrated northward and eastward during the Oligocene and early Miocene. Because of the absence or subsequent erosion of traps, it is likely that the southernmost source rocks expelled most of their oil without any appreciable accumulation. Our modeling indicates that there were two important kitchens during the Cenozoic. The larger of the two was located in the present-day Eastern Cordillera, and it was most productive in the late Eocene–early Oligocene. The second kitchen, which generated oil throughout the Neogene, was located in the foredeep of the Llanos basin, adjacent to the mountain front. Considerable amounts of oil from this recent pulse have accumulated in both deep and shallow reservoirs along the eastern foothills. The modeled reservoir charge history also explains the substantial biodegradation of oils in reservoirs that are today much too deep to support the process. Biodegradation must have occurred when the reservoirs were shallower and at cooler temperatures, and they remained active until the reservoirs were buried to depths where temperatures were high enough to prevent further bacterial activity.

Description: 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.

Description: FetKin is a C++ program for forward modeling thermochronological ages on a two-dimensional geological cross section. Modeled ages for various thermochronometers are computed from time–temperature histories that result from coupling the modeled kinematics of deformation obtained from commercial software for balanced reconstructions (2DMove) and a finite element computation of temperatures. Additional capabilities include the ability to accommodate (1) a smooth change of topological relief; (2) the influence of variation in rock physical properties; and (3) multikinetic modeling of fission-track ages and length distributions, as well as apatite and zircon (U-Th)/He and muscovite $$^{40}\mathrm{Ar}/^{39}\mathrm{Ar}$$ systems. A joint first-order analysis of the impact of erosion parameters and material properties improves age predictions and allows for a more complete analysis of observed cooling ages based on their modeled thermal histories. Thus, this paper presents a new software tool that has been developed as a basic support for the methodological approach used to build the kinematic restorations shown in this volume, which are the basic input for petroleum systems modeling and prediction in the Colombian Eastern Cordillera and Llanos foothills basin.

Description: Analysis of fracture systems in subsurface structures is limited by the amount and uncertainty of available data. With the aim of analyzing the distribution of fracture systems, we studied surface structures as analogs for oil fields in the fractured reservoirs of the Llanos foothills of Colombia. Here, we document the presence of four widespread fracture systems whose distribution is related to fold geometry and folding mechanism. At surface, in the Tierranegra and Silbadero anticlines, the principal fracture systems are symmetrical with respect to northeast- and northwest-trending fold axes, showing higher fracture intensities in the forelimbs of the structures. In the Guavio anticline, higher fracture intensities are located in the backlimb, with principal east–west and northwest–southeast directions. In contrast, we document northeast–southwest fractures near the hinge zones in the adjacent synclines. This distribution suggests that in the Guavio anticline, fractures respond to movement of the hanging-wall above a ramp, consistent with a fault-bend-fold model. Whereas, in the Tierranegra and Silbadero anticlines, fractures respond to limb rotation and hinge migration consistent with detachment fold models. Comparing these with subsurface structures, we identified that El Morro anticline has fracture distributions like those in the Tierranegra and Silbadero anticlines, but have higher fracture intensities. In the case of the Cusiana Structure, fracture intensities are higher in the crest but not in the limbs, and intensities differ from the ones found in the Guavio anticline, showing that these structures are not appropriate analogs. The results show how fracture distribution depends on structural position and fold evolution, and is controlled in part by folding mechanism. This suggests that models based on Holocene fold geometry cannot accurately predict the observed fracture distributions and should not be used to construct discrete fracture network models. Instead, the patterns we describe can be used as a guide for similar structures. Our work illustrates the possibility of having different fracture patterns and fracture abundances in adjacent folds in the same fold-thrust belt.

Description: Electromagnetic (EM) methods were used to characterize (1) the general near-surface geology and stratigraphy and (2) the initial electrical conductivity distribution at a $${\mathrm{CO}}_{2}$$ enhanced oil recovery (EOR) site to assess and monitor possible near-surface environmental impacts of a carbon sequestration experiment. The field study was conducted at Cranfield Field, an EOR site where $${\mathrm{CO}}_{2}$$ is being injected into a depleted oil and gas reservoir in the Cretaceous lower Tuscaloosa Formation in western Mississippi. The study focused on Tertiary and younger strata between the ground surface and maximum depths of approximately 200 m (656 ft) that host groundwater more than 3000 m (9843 ft) above the oil and gas reservoir and injection zone. It included an airborne geophysical survey collecting frequency-domain EM data, time-domain surface EM measurements, borehole logging with EM induction, natural gamma spectra, and water-level measurements. Different approaches of temperature drift corrections for the borehole EM data were compared; good results of consistent and accurate conductivity values were produced by combining both directions of a two-way (uphole and downhole) measurement. The airborne EM provided data over a large area with sufficient detail to give an overview for the subsequent surface and borehole surveys, the surface time-domain data gave insight into greater depths, and the borehole induction data provided the necessary details. These three EM methods complement each other in areal coverage, lateral and vertical resolution, and exploration depth. Together, they can provide a comprehensive near-surface characterization of the study area that is necessary to establish initial-state conditions that support future monitoring of potential $${\mathrm{CO}}_{2}$$ migration to the near-surface environment.

Description: Forced folds typically develop above the tips of propagating normal faults in rifts that contain thick, prerift salt or mudstone sequences. This structural style is associated with the deposition of wedge-shaped synrift deposits that thin and onlap toward monoclinal growth folds overlying the vertically restricted fault tips. Subtle stratigraphic traps may develop on the flanks of these folds although, because of limited seismic resolution and sparse well data, the architecture, thickness, and distribution of these early synrift reservoirs are difficult to predict. To improve our understanding of early synrift reservoir development on the flanks of forced folds, we focus on seismic-scale outcrop analogs along the Hadahid fault system, Suez rift, Egypt. Our data indicate that forced folding dominated during early rifting and that the onset of folding was diachronous along strike. Fluvial systems incised the rotating monocline limbs, leading to the formation of valley-like erosional relief along the base synrift unconformity. Reservoir-prone fluvial facies are only locally developed along the forced-fold flank, with their distribution related to the degree of sediment bypass downdip into the adjacent basin. Early synrift relief not filled by fluvial strata was backfilled by transgressive, tidally influenced, reservoir-prone facies, with carbonates being locally developed in areas of low clastic sediment supply. Further extension and fault-tip propagation led to amplification of the forced folds, and deposition of shallow marine-to-shelf parasequences that became thinner toward the growing folds. Although displaying greater strike continuity than the underlying fluvial or tidal reservoirs, shoreface sandstone reservoirs amalgamate onto the flanks of the forced folds and may be absent toward the fold crest. This seismic-scale outcrop analog helps us better understand the subseismic stratigraphic architecture and facies distributions of early synrift reservoirs on the flanks of extensional forced folds. Observations from this and other well-exposed outcrop analogs should help reduce subsurface uncertainty and risk when exploring for hitherto under-explored, subtle, early synrift stratigraphic traps.

Description: Clinoform surfaces control aspects of facies architecture within shallow-marine parasequences and can also act as barriers or baffles to flow where they are lined by low-permeability lithologies, such as cements or mudstones. Current reservoir modeling techniques are not well suited to capturing clinoforms, particularly if they are numerous, below seismic resolution, and/or difficult to correlate between wells. At present, there are no modeling tools available to automate the generation of multiple three-dimensional clinoform surfaces using a small number of input parameters. Consequently, clinoforms are rarely incorporated in models of shallow-marine reservoirs, even when their potential impact on fluid flow is recognized. A numerical algorithm that generates multiple clinoforms within a volume defined by two bounding surfaces, such as a delta-lobe deposit or shoreface parasequence, is developed. A geometric approach is taken to construct the shape of a clinoform, combining its height relative to the bounding surfaces with a mathematical function that describes clinoform geometry. The method is flexible, allowing the user to define the progradation direction and the parameters that control the geometry and distribution of individual clinoforms. The algorithm is validated via construction of surface-based three-dimensional reservoir models of (1) fluvial-dominated delta-lobe deposits exposed at the outcrop (Cretaceous Ferron Sandstone Member, Utah), and (2) a sparse subsurface data set from a deltaic reservoir (Jurassic Sognefjord Formation, Troll Field, Norwegian North Sea). Resulting flow simulation results demonstrate the value of including algorithm-generated clinoforms in reservoir models, because they may significantly impact hydrocarbon recovery when associated with areally extensive barriers to flow.

Description: Permeability contrasts associated with clinoforms have been identified as an important control on fluid flow and hydrocarbon recovery in fluvial-dominated deltaic parasequences. However, they are typically neglected in subsurface reservoir models or considered in isolation in reservoir simulation experiments because clinoforms are difficult to capture using current modeling tools. A suite of three-dimensional reservoir models constructed with a novel, stochastic, surface-based clinoform-modeling algorithm and outcrop analog data (Upper Cretaceous Ferron Sandstone Member, Utah) have been used here to quantify the impact of clinoforms on fluid flow in the context of (1) uncertainties in reservoir characterization, such as the presence of channelized fluvial sandbodies and the impact of bed-scale heterogeneity on vertical permeability, and (2) reservoir engineering decisions, including oil production rate. The proportion and distribution of barriers to flow along clinoforms exert the greatest influence on hydrocarbon recovery; equivalent models that neglect these barriers overpredict recovery by up to 35%. Continuity of channelized sandbodies that cut across clinoform tops and vertical permeability within distal delta-front facies influence sweep within clinothems bounded by barriers. Sweep efficiency is reduced when producing at higher rates over shorter periods, because oil is bypassed at the toe of each clinothem. Clinoforms are difficult to detect using production data, but our results indicate that they significantly influence hydrocarbon recovery and their impact is typically larger than that of other geologic heterogeneities regardless of reservoir engineering decisions. Clinoforms should therefore be included in models of fluvial-dominated deltaic reservoirs to accurately predict hydrocarbon recovery and drainage patterns.

Description: Raman spectroscopy has been used extensively in thermal maturation studies of kerogen, but has not been used to examine the maturation of organic cements in agglutinated foraminifera. Here, we use Raman spectroscopy to document the existence of carbonaceous matter and silica in recent and fossil agglutinated foraminifera, and to measure thermal alteration effects in fossil foraminifera. The distribution of carbonaceous matter through the test (shell) walls of agglutinated foraminifera suggests that this carbonaceous material is derived from primary organic cement and not from random contamination. Fossil specimens exhibit three broad stages of maturation: (1) Immature specimens are characterized by moderately strong fluorescence, broad, low intensity Raman peaks (relative to fluorescence), and a tendency for the G-band to occur at lower wave numbers. These attributes are consistent with the presence of amorphous carbonaceous matter and minor organic degradation. (2) Mature samples (oil window) exhibit high fluorescence, increased relative D- and G-band intensities, and a decreased width of the D-band. (3) Postmature samples exhibit low levels of fluorescence and high relative D- and G-band intensities, a tendency for the G-band to be located at higher wave numbers, an increase in the D:G band ratio, and an increase of the relative intensity of the silica peak. This stage is consistent with the presence of highly ordered carbonaceous matter and diagenetic quartz. These findings indicate that Raman spectroscopic analysis of fossil agglutinated foraminifera can be used as a quick and easy tool to assess thermal maturity and estimate optimal temperatures for hydrocarbon generation.

Description: 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.

Description: Outcrop chalk of late Campanian age (Gulpen Formation) from Liège (Belgium) was flooded with $${\mathrm{MgCl}}_{2}$$ in a triaxial cell for 516 days under reservoir conditions to understand how the non-equilibrium nature of the fluids altered the chalks. The study is motivated by enhanced oil recovery (EOR) processes because dissolution and precipitation change the way in which oils are trapped in chalk reservoirs. Relative to initial composition, the first centimeter of the flooded chalk sample shows an increase in MgO by approximately 100, from a weight percent of 0.33% to 33.03% and a corresponding depletion of CaO by more than 70% from 52.22 to 14.43 wt.%. Except for Sr, other major or trace elements do not show a significant change in concentration. Magnesite was identified as the major newly grown mineral phase. At the same time, porosity was reduced by approximately 20%. The amount of $${\mathrm{Cl}}^{-}$$ in the effluent brine remained unchanged, whereas $${\mathrm{Mg}}^{2+}$$ was depleted and $${\mathrm{Ca}}^{2+}$$ enriched. The loss of $${\mathrm{Ca}}^{2+}$$ and gain in $${\mathrm{Mg}}^{2+}$$ are attributed to precipitation of new minerals and leaching the tested core by approximately 20%, respectively. Dramatic mineralogical and geochemical changes are observed with scanning electron microscopy–energy-dispersive x-ray spectroscopy, nano secondary ion mass spectrometry, x-ray diffraction, and whole-rock geochemistry techniques. The understanding of how fluids interact with rocks is important to, for example, EOR, because textural changes in the pore space affect how water will imbibe and expel oil from the rock. The mechanisms of dissolution and mineralization of fine-grained chalk can be described and quantified and, when understood, offer numerous possibilities in the engineering of carbonate reservoirs.

Description: 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.

Description: Spontaneous-potential (SP) log data from wells in the deep eastern Greater Green River Basin (GGRB) suggest that what appears to be overpressured pervasive gas at high saturation in Upper Cretaceous sandstones outside conventional fields is gassy water with gas present at uneconomically low saturation. Sandstones of the Lewis Shale and Mesaverde Group within conventional-trap fields in the deep eastern GGRB exhibit normal-SP deflections, indicating saline formation water with low formation-water resistivity ( $${R}_{\mathrm{w}}$$ ) that yields calculated water saturations $$({S}_{\mathrm{w}})$$ less than 50%. However, in deep-basin areas outside conventional traps, these Upper Cretaceous sandstones generally exhibit reversed-SP signatures reflecting anomalously low-salinity formation water with anomalously high $${R}_{\mathrm{w}}$$ that yields calculated $${S}_{\mathrm{w}}$$ greater than 60%. Uneconomically low gas saturations are corroborated by lack of commercial gas production from reversed-SP sandstones despite (1) prominent gas shows during drilling, (2) significant overpressure, and (3) log-measured porosity and resistivity that often are indistinguishable from those observed with commercially productive normal-SP sandstones within conventional traps. Anomalously low-salinity water in deep-basin sandstones outside conventional traps is proposed to result from dilution of original saline formation water by fresh water expelled during smectite-clay conversion to illite with increasing temperature (burial depth). Low permeability of deep-basin sandstones retards escape of the added fresh water, which contributes to overpressure and to deceptively high formation resistivity. Although the upward transition to more saline formation water is gradational, mapped top of reversed SP cuts across stratigraphic boundaries, with relief exceeding 2000 ft (610 m). It is unclear whether regional continuous gas in reversed-SP sandstones has been at low saturation since the onset of gas migration or whether saturations were higher prior to the influx of fresh water. What is reasonably certain is that subsequent to gas migration, fresh-water influx in the deep basin regionally diluted original saline formation water outside conventional traps. Similar formation-water salinity of normal-SP sandstones of the Lewis Shale and Mesaverde Group within deep-basin conventional traps suggests that high-saturation gas and associated irreducible saline formation water in these fields are locked-in accumulations unaffected by subsequent fresh-water influx.

Description: Methane-rich gas occurs in the total organic carbon–rich Alum Shale (Furongian to Lower Ordovician) in southern Sweden. The lower part of the thermally immature Alum Shale was impregnated by bitumen locally generated by heating from magmatic intrusions from the Carboniferous to the Permian. Organic geochemical data indicate that the migrated bitumen is slightly degraded. In the upper Alum Shale, where methane is the main hydrocarbon in thermovaporization experiments, centimeter-size calcite crystals occur that contain fluid inclusions filled with oil, gas, or water. The Alum Shale is thus considered a mixed shale oil–biogenic shale gas play. The presented working hypothesis to explain the biogenic methane occurrence considers that water-soluble bitumen components of the Alum Shale were converted to methane. A hydrogeochemical modeling approach allows the quantitative retracing of inorganic reactions triggered by oil degradation. The modeling results reproduce the present-day gas and mineralogical composition. The conceptual model applied to explain the methane occurrence in the Alum Shale in southern Sweden resembles the formation of biogenic methane in the Antrim Shale (Michigan Basin, United States). In both models, melting water after the Pleistocene glaciation and modern meteoric water may have diluted the contents of total dissolved solids (TDS) in basinal brines. Such pore waters with low TDS contents create a subsurface aqueous environment favorable for microbes that have the potential to form biogenic methane. Today, biogenic methane production rates, with shale as the substrate using different hydrocarbon-degrading microbial enrichment cultures in incubation experiments, range from 10 to 620 nmol per gram and per day.

Description: In recent years, fracture-controlled (hydrothermal) dolomitization in association with igneous activity has gained interest in hydrocarbon exploration. The geometry and distribution of dolomite bodies in this setting are of major importance for these new plays. The Latemar platform presents a spectacularly exposed outcrop analogue for carbonate reservoirs affected by igneous activity and dolomitization. Light detection and ranging (LIDAR) scanning and digital outcrop models (DOMs) of outcrops offer a great opportunity to derive geometrical information. Only a few analysis methods exist to quantitatively assess huge amounts of georeferenced three-dimensional lithology data. This study presents a novel quantitative approach to describe three-dimensional spatial variation of lithology derived from DOMs. This approach is applied to the Latemar platform to determine dolomite body geometry and distribution in relation to crosscutting dikes. A high-resolution photorealistic DOM of the Latemar platform allows description of dolomite occurrences in three dimensions, with high precision at platform scale. This results in a unique lithology dataset of limestone, dolomite, and dike positions. This dataset is analyzed by true three-dimensional variography for the geospatial description of dolomite distribution. In most studies, three-dimensional geostatistics is the combination of two-dimensional horizontal and one-dimensional vertical variation. In this study, the dolomite occurrences are extensive in three dimensions and cannot be reduced to a two-dimensional + one-dimensional case. Therefore, the concept of two-dimensional variogram maps is expanded to a three-dimensional description of lithology variation. Three-dimensional anisotropy detection is used to derive principal directions in the occurrence of dolomite. Two small-scale (〈200 m [656 ft]) anisotropy directions emerge, one vertical and one subhorizontal, which describe the geometry of the dolomite bodies. These principal directions are perfectly aligned parallel to the average dike orientation. On platform scale (200–1600 m [656–5249 ft]) a bedding-parallel anisotropy direction indicates stratigraphic control on dolomite occurrences.

Description: The Hudson Bay Basin is the largest intracratonic basin in North America, although it is the only one without any proven hydrocarbon reserves. The stratigraphic succession that fills the basin consists mainly of Paleozoic strata, with a maximum preserved thickness of about 2500 m (8202 ft). The Paleozoic succession includes Ordovician to Devonian shallow marine carbonates, reefs, and shales with locally thick Devonian evaporites. The Paleozoic strata are locally unconformably overlain by a thin Mesozoic and Cenozoic cover of nonmarine and marine strata. From 1964 to 1985, over 46,000 line-km (28,600 mi) of seismic reflection data were acquired, and four onshore and five offshore exploration wells were drilled. The data acquired at that time led to pessimistic conclusions on source rocks and the thermal rank of the basin and resulted in the stoppage of exploration activities. However, hydrocarbon shows or indicators were identified in well log data and seismic reflection profiles. The likelihood of an active petroleum system has also been recently supported by recognition of pockmarks on the seafloor and possible marine oil slicks identified on satellite images. New studies of geological, geophysical, and biostratigraphic data reveal that the Hudson Bay Basin had an irregular subsidence and uplift history. Syntectonic deposition occurred during the Late Ordovician(?) to Early Devonian and sag-basin deposition during the Middle to Late Devonian. The basin contains four unconformity-bounded sequences, with significant depocenter migration over time. Analyses of petroleum-system data indicate the Hudson Bay Basin has higher petroleum potential than previously considered. Porous platform limestones, reefs, hydrothermal dolomites, and siliciclastics form potential hydrocarbon reservoirs. Upper Ordovician organic-rich shales with type II-S organic matter are recognized at several locations in the basin. Newly acquired organic matter reflectance and Rock-Eval $${T}_{\mathrm{max}}$$ data indicate Ordovician–Silurian strata locally reached the oil window. Basin modeling demonstrates significant potential for oil generation and expulsion from Ordovician source rocks. Five petroleum play types are identified in the Hudson Bay Basin, including an untested fault-sag or hydrothermal dolomite play. The synthesis of the petroleum system information indicates that the Hudson Bay Basin is, at least locally, prospective for oil accumulations.

Description: The Permian White Rim Sandstone is a partly exhumed, primary reservoir of the Tar Sand Triangle accumulation in southeastern Utah. In the Elaterite Basin (Canyonlands National Park and Glen Canyon National Recreation Area), the White Rim Sandstone is well exposed and varies in color from white to red, orange, and brown. Superimposed on eolian and marine deposits are three diagenetic facies that impart the coloration and are defined by iron oxide cement concentration as (1) bleached white (low iron), (2) diffuse (moderate iron), and (3) concretionary (concentrated iron). A yellow alteration aureole of bleaching extends up to 10 m (32 ft) into the underlying Organ Rock Shale and up to 20 m (65 ft) into the overlying Moenkopi Formation. These formations surround the White Rim reservoir as fine-grained seals. Field, petrographic, and geochemical analyses indicate that the White Rim Sandstone records three major diagenetic stages. (1) The reservoir underwent oxidation, which led to the precipitation of thin iron grain coatings. (2) Hydrocarbon migration through the reservoir removed early grain coatings and reprecipitated disseminated and concentrated pyrite cement. (3) The pyrite was later altered to hematite or goethite by oxidizing fluids. In conventional petroleum exploration, the timing of hydrocarbon migration is often difficult to resolve. This study utilizes the record of mobilized and reprecipitated iron as a tool to constrain interpretations of the timing of hydrocarbon migration relative to seal and trap emplacement. This study has broad application as an exploration tool for deciphering fluid flow in similar clastic reservoirs.

Description: 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).

Description: Few previous studies have focused on solid bitumen distribution and its effect on gas reservoir quality during oil cracking. Solid bitumen is commonly found in both gas and nongas reservoirs of the Triassic Feixianguan Formation $$({\mathrm{T}}_{1}\mathrm{f})$$ in the Jiannan gas field. The $${\mathrm{T}}_{1}\mathrm{f}$$ natural gases are mainly secondary cracking gases of oil generated from source rock of the Permian Wujiaping Formation $$({\mathrm{P}}_{2}\mathrm{w})$$ , and the reservoir experienced temperatures above 150°C (302°F) for about 35 m.y. A relatively narrow range of $$\mathrm{ln}({\mathrm{C}}_{1}/{\mathrm{C}}_{2})$$ values and a wide range of $$\mathrm{ln}({\mathrm{C}}_{2}/{\mathrm{C}}_{3})$$ values and widespread solid bitumen indicate that oil cracking took place in the gas field. Low concentrations of $${\mathrm{H}}_{2}\mathrm{S}$$ (commonly 〈0.81%) suggest that high-reflectance (2.57%–3.07%) solid bitumens are pyrobitumens, which would have been mainly derived from oil cracking. Gases preferentially occupy larger pore spaces, and oil is displaced into small pores and throats by overpressure during oil cracking. In this way, pyrobitumens can reduce the magnitude of porosity in relatively tight reservoirs. Moderate-quality oil reservoirs (paleoporosity 2.2%–8.0%) are between or adjacent to high-quality oil reservoirs and are probably poor-quality or nongas reservoirs after oil cracking. Carbonate reservoirs (paleoporosity 〉8.0%) can be high-quality gas reservoirs after oil cracking and should be favorable targets for future gas exploration in the northeastern Sichuan Basin and adjacent areas.

Description: We examined cataclastic shear bands (CSB) with varying degrees of deformation and alteration that formed in uncemented, arkosic sediments under identical kinematic conditions. The investigated outcrop in eastern Austria exposes numerous closely spaced sets of CSB formed at low burial depth. The uncemented host sediment consists of detrital quartz, albite, micas, and metamorphic lithoclasts. We distinguished three types of CSB, which differ in macroscopic and microscopic properties as well as in influence on fluid flow (i.e., single bands, multistrand bands, and band clusters). All band types show preferred fracturing of sericited albite grains and decomposition of biotite through mechanical deformation and subsequent chemical alteration. These mechanisms reduce the mean grain size, increase the amount of phyllosilicates in the matrix, and facilitate later growth of authigenic clay minerals. The dominant deformation mechanisms and influence on fluid flow are controlled by the initial composition and intensity of diagenetic alteration. We identified different evolutionary stages from a high-porosity host rock ( $$\hbox{ porosity }[\mathrm{\Phi }]=35\%$$ ) to a deformation band cluster ( $$\mathrm{\Phi }=6\%$$ ) that acts as fluid baffle. The measured reduction in porosity of up to 29% is reflected by retention of fluids along band clusters, along multistrand bands, and between intersecting bands. The timing and direction of the specific fluid flows can be determined by the interaction with the deformation bands. These findings suggest that localized deformation and associated diagenetic alteration in feldspar-bearing sediments may promote reservoir compartmentalization.

Description: 〈span〉〈div〉ABSTRACT〈/div〉Late Cretaceous–to–present-day mixed carbonate–clastic deposition along the Nicaraguan platform, western Caribbean Sea, has evolved from a tectonically controlled, rifted upper Eocene shallow–to–deep-marine carbonate–siliciclastic shelf to an upper Miocene–to–present-day tectonically stable shallow-marine carbonate platform and passive margin. By integrating subsurface data of 287 two-dimensional seismic lines and 27 wells, we interpret the Cenozoic stratigraphic sequence as 3 cycles of transgression and regression beginning with an upper Eocene rhodolitic–algal carbonate shelf that interfingered with marginal siliciclastic sediments derived from exposed areas of Central America bordering the margin to the west. During the middle Eocene, a carbonate platform was established with both rimmed reefs and isolated patch reefs. A late Eocene forced regression produced widespread erosion and subaerial exposure across much of the platform and was recorded by a regional unconformity. The Oligocene–upper Miocene sedimentary record includes a southeastward prograding delta of the proto-Coco river, which drained the emergent area of what is now northern Nicaragua. The late Miocene–to–present-day period marks a period of strong subsidence with the development of small pinnacle reefs. We describe favorable petroleum system elements of the Nicaraguan platform that include (1) Eocene fossiliferous limestone source rocks documented as thermally mature in vintage exploration wells and seen as active gas chimneys emanating from inferred carbonate reservoirs; (2) upper–to–middle Eocene reservoirs in patch and pinnacle reefs, middle Eocene calcareous slumps, and Oligocene fluvial-deltaic facies documented in wells; and (3) regional seal intervals that consist of both regional unconformities and Eocene–Oligocene intraformational shale.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Fault damage zones may significantly affect subsurface fluid migration and the development of unconventional resources. Most analyses of fault damage zones are based on direct field observations, and we expand these analyses to the subsurface by investigating the damage zone structure of an approximately 32-km (∼10〈sup〉5〈/sup〉-ft)-long right-lateral strike-slip fault in Oklahoma. We used the three-dimensional (3-D) seismic attribute of coherence to first define its regional and background levels, and then we evaluated the damage zone dimensions at multiple sites. We found damage zone thickness of approximately 1600 m (∼5300 ft) at a segment that is dominated by subsidiary faults, and it is slightly thicker at a segment with a pull-apart basin. The damage zone intensity decays exponentially with distance from the fault core, in agreement with field observations and distribution of seismic events. The coherence map displays a strong asymmetry of the damage zone between the two sides of the 3-D fault, which is related to the subsidiary structures of the fault zone. We discuss the effects of heterogeneous stress field on damage zone evolution through the detected subsidiary structures. It appears that seismic coherence is an effective tool for subsurface characterization of fault damage zones.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Some fault zones leak vertically to the ground surface or seafloor, whereas most others remain naturally sealed. Understanding the factors that cause this leakage is essential for predicting and preventing such leakage for both conventional reservoir development and subsurface CO〈sub〉2〈/sub〉 storage. This study, a comparison of leaking and nonleaking natural CO〈sub〉2〈/sub〉 gas accumulations, provides such constraints. We compare and contrast trap configurations, fluid pressures, and stress states for several natural CO〈sub〉2〈/sub〉 accumulations from the Colorado Plateau. Extensive surface geologic data are integrated with subsurface data from a large suite of groundwater and hydrocarbon wells. Leakage of CO〈sub〉2〈/sub〉 is documented by geochemical surveys and the occurrence of extensive travertine deposits. The leakage occurs exclusively in fault fracture damage zones where the total fluid pressure reduces the minimum horizontal effective stress to approximately zero. These results are consistent with natural and accidentally induced fault seeps from some deep-water hydrocarbon reservoirs. These criteria can be used to evaluate the potential for fault zones to provide vertical leakage pathways and loss of fluid containment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The three-dimensionally complex, highly progradational mixed siliciclastic–carbonate strata of the San Andres and Grayburg Formations have long been the backbone of conventional hydrocarbon reservoir production from the Permian Basin, and significant recovery continues via waterflooding and CO〈sub〉2〈/sub〉 injection. Besides, nonreservoir equivalents of these formations have recently taken increasing significance as produced water disposal targets. However, seismic-stratigraphic interpretations are challenged by complex internal shelfal-stratal geometries and numerous laterally continuous but vertically thin fluid barriers in overlying platforms. We built a three-dimensional (3-D) geocellular model of Guadalupian 8–13 high-frequency sequences (G8–G13 HFSs) and then conducted forward seismic modeling (35-Hz 0° phase). This allows investigations on the validity of applying conventional reflection-geometry–based interpretation to delineate the G9 HFS top and base, which can potentially serve as bounding/constraining surfaces for upper San Andres shelf–Grayburg platform reservoirs. This study contributes to 3-D modeling methodologies by introducing a query tree to select geostatistical methods for modeling dual-scale heterogeneities and by integrating data from diverse sources for seamless and realistic 3-D models. Our seismic-stratigraphic evaluation demonstrates that conventional reflection–geometry-based interpretation does not adequately resolve the G9 top and base; deviations from the geocellular model reach up to 80 m (260 ft) and are thus well beyond the maximum acceptable error limits of ±0.5 wavelength. We suggest improving conventional interpretations of the G9 base by selective interpolation or mixed-polarity event picking near the error-prone shelf margin and upper slope. Besides, instead of picking the highly discontinuous seismic peak as G9 top, bulk-shifting of a shallower trough horizon near actual G10 top should deliver a more accurate surface representing G9 top.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Paleogene shale of the Dongying depression, a continental basin in eastern China, is taken as the study subject to examine the microscopic features of lacustrine shale reservoirs in the oil window. This study shows that shale pores in this evolutionary stage are present at the micrometer to nanometer scale, but fractures commonly have extension distances at the millimeter scale. Pores and fractures can be divided into three types, namely, primary pores, secondary pores, and cracks. Primary pores commonly have good connectivity at shallow burial depth. With the increase of burial depth, primary porosity is reduced because of compaction and cementation. Secondary pores are important in shale, including dissolved pores inside grains and at grain edge, and dissolution pores inside the hybrid of organic matter (OM) and clay minerals, and evaporite minerals, including carbonates or sulfates. Types of cracks were observed: bedding fissures, dissolution fractures, and structural fractures. The development of bedding fissures is related to the deposition of shale laminae. The formation of dissolution fractures is related to acidic fluids, such as organic acids and hydrogen sulfide, whereas the formation of structural fractures is jointly controlled by fault development, fluid overpressure, and lithofacies. The pores and fractures in the oil window of lacustrine shale can store and channel oil and gas. The hybrid OM–clay–carbonate (sulfate) and the pores inside are important through the oil window. Moreover, the development of the pores depends not only on hydrocarbon generation but also on the interaction of hydrocarbons and organic acid dissolution. This finding has important significance in the accumulation of oil and gas in continental shales.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the past, determination of rock properties using image analysis relied upon petrographic transmitted-light images, but with limited success because of a lack of resolution and restricted computer processing power. A new technique that employs confocal laser scanning microscopy (CLSM) can be considered complementary to laboratory measurements and applicable to several samples, saving time and money and requiring only a limited amount of rock sample for analysis. We have studied several types of rocks with CLSM and fluorescent dye–impregnated thin sections. The two-dimensional scans of each thin section images is an area of 12 mm〈sup〉2〈/sup〉, with a pixel size of 0.198 µm and were used to simulate capillary pressure curves for pore bodies and pore throats. The CLSM technique also enables three-dimensional (3-D) visualization of the rock porosity. The studied rock samples were taken from diverse oil and gas field reservoirs: case A, a conventional sandstone (15.1% porosity, 29.8 md permeability); case B, a tight sandstone (3.7%, 0.02 md); case C, an oolitic carbonate (9.6%, 0.1 md); case D, a rhodolithic algal carbonate (19.8%, 43.7 md); case E, dolomitized carbonate (17%, 21.7 md); and case F, a naturally fractured carbonate (2.4%, 0.6 md). Our results confirm that the CLSM technique can be applied to rocks of contrasting porosity and permeability to obtain computed synthetic capillary pressure curves faster than with conventional measurement methods. The technique quantifies different pore-body and pore-throat sizes and distributions, with the added ability to visualize 3-D porosity and to extract from thin section analysis petrologic properties.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Oil API gravity predictions using published basin modeling source rock (SR) reaction kinetics have displayed poor matches between modeled output and field observations because these kinetic models do not predict increasing API gravities with increasing maturity. Ideally, an SR kinetic model should use at least two liquid components of different densities, which are generated and expelled from the SR such that the API gravities are a consequence of relative mixing. Very few available kinetic models predict APIs with reasonable trends, but those are either not adjustable to calibrate to field observations or do not consider sorption, which is a necessary process when evaluating unconventional resources. Five new kinetics data sets are presented in this paper, each representing a standard SR type, which provide geologically reasonable API gravity trends and ranges. Each kinetic model uses two liquid pseudocomponents and two vapor pseudocomponents. The relative ratios between the pseudocomponents at full kerogen transformation are average ratios available from public and proprietary kinetic data sets. The primary generation follows published activation energies, including minor shifts, which allow peak generation to occur at lower activation energies for the heavier liquid pseudocomponent and at higher energies for the lighter one. This systematic shift of activation energies thus results in a constant change in API gravity as primary generation progresses. Additional in-SR sorption and secondary cracking schemes support the primary generated API gravity trends. The default ranges of API gravity for the new five kinetic models represent observed averages but can be adjusted easily.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Shale gas in the Sichuan Basin and its periphery potentially plays an important role in the world shale gas industry. An understanding of remigration and leakage from continuous shale reservoirs is very important for shale gas exploration, especially in the Sichuan Basin and its periphery. The shale gas accumulation models that relate to remigration and leakage were developed within the Wufeng and Longmaxi black shales in the Jiaoshiba and the Youyang blocks. First, a tectono-sedimentary history of the Wufeng and Longmaxi black shales in the Sichuan Basin and its periphery was developed based on the published literature. The history exhibits a continuous distribution of high-quality Wufeng and Longmaxi black shale, which is the foundation of the shale gas formation. Second, the shale gas remigration–accumulation model in the anticlines was clarified by using data collected from the shale gas fields in Jiaoshiba block. The shale gas model for the Jiaoshiba block was developed on the basis of a continuous shale reservoir distribution, differentiated structural deformation, and a gas self-sealed system. Third, the shale gas fault failure leakage model in the fault blocks and the erosion model in the residual areas were revealed based on the shale reservoir and shale gas content heterogeneity in the Youyang block. These two models were validated by available data including 13 two-dimensional seismic lines and 2 shale gas exploration vertical wells in the Youyang block. Shale gas areas with high gas resource and gas production rates in the anticlines were defined by the remigration–accumulation model. The fault failure leakage model was used to find shale gas with limited commercial potential, whereas commercial shale gas was largely lacking according to the erosion residual model. The study on remigration and leakage from continuous shale reservoirs in the Sichuan Basin and its periphery can be used to better understand and improve the exploration efforts based on resource preservation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉For both modeling and management of a reservoir, pathways to and through the seal into the overburden are of vital importance. Therefore, we suggest applying the presented structural modeling workflow that analyzes internal strain, elongation, and paleogeomorphology of the given volume. It is assumed that the magnitude of strain is a proxy for the intensity of subseismic scale fracturing. Zones of high strain may correlate with potential migration pathways. Because of the enhanced need for securing near-surface layer integrity when CO〈sub〉2〈/sub〉 storage is needed, an interpretation of three-dimensional (3-D) seismic data from the Cooperative Research Centre for Greenhouse Gas Technologies Otway site, Australia, was undertaken. The complete 3-D model was retrodeformed. Compaction- plus deformation-related strain was calculated for the whole volume. The strain distribution after 3-D restoration showed a tripartition of the study area, with the most deformation (30%–50%) in the southwest. Of 24 faults, 4 compartmentalize different zones of deformation. The paleomorphology of the seal formation is determined to tilt northward, presumably because of a much larger normal fault to the north. From horizontal extension analysis, it is evident that most deformation occurred before 66 Ma and stopped abruptly because of the production of oceanic crust in the Southern Ocean. Within the seal horizon, various high-strain zones and therefore subseismic pathways were determined. These zones range in width from 50 m (164 ft) up to 400 m (1312 ft) wide and do not simply follow fault traces, and—most importantly—none of them continue into the overburden. Such information is relevant for reservoir management and public communication and to safeguard near-surface ecologic assets.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the last 30 yr, basin and petroleum system modeling (BPSM) has evolved into a large and diverse field encompassing a broad range of scientific disciplines. As BPSM is applied to an increasingly wide range of problems, what are, or should be, the future directions in the evolution of BPSM comes into question.To address this question, a survey was conducted at the AAPG Hedberg Research Conference on “The Future of Basin and Petroleum Systems Modeling,” held in Santa Barbara, California, April 3–8, 2016. To capture the full range of thoughts, participants were asked to list in priority order what they think are the three most important future directions in BPSM. The responses were collated into six general categories for analysis. The categorization process involved some qualitative judgements because some areas spanned several of the general areas.The results show that the most frequently cited directions are related to BPSM workflows, organizations, and processes. This category includes how modelers are used in an organization, how projects are executed, and how the results are interpreted and integrated.Migration modeling (primary and secondary) is the most frequently cited technical need. The results indicate that migration processes are not well understood and there are still substantial differences of thought about the processes involved and the best ways to model them.Some subjects, such as uncertainty and unconventionals, were mentioned in several of the general categories, whereas other subjects, such as increased functionality in the models, were only seldom mentioned.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Natural fractures are important storage spaces and fluid-flow channels in tight-oil sandstones. Intraformational open fractures are the major channels for fluid flow in tight-oil sandstones. Small faults may provide fluid-flow channels across different layers. According to analogous outcrops, cores, and borehole image logs, small faults and intraformational open fractures are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. Among them, high dip-angle intraformational open fractures are the most abundant. Northeast-southwest–trending fractures are the principal fractures for fluid flow because that is the present-day maximum horizontal compressive stress direction. Combined with production data, horizontal wells, striking normal to or at a large angle relative to the major flow pathways, are beneficial for tight-oil production improvement. Fractures with high dip angles are the main factor that influences initial oil production. Linkage and tip damage zones are more favorable for oil production improvement than wall damage zones. This study provides an example of natural fracture characterization and unravels fracture contributions to reservoir physical properties and oil production of tight-oil sandstones, which could provide a geological basis for oil exploration and development in tight sandstones.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Using recently acquired three-dimensional seismic data, we summarize typical patterns for seismic-based identification and stage analysis of sedimentary units in the Eocene succession of the southern slope-break belts of the Bozhong sag, Bohai Bay Basin, China. The sedimentary units in the study area are characterized by progradational reflectors and mound-shaped, bidirectional downlapping reflectors in dip and strike directions, respectively. Differential characteristics of a distinct sedimentary unit within one lobe are documented. The major provenance direction is defined and characterized by the largest dip angles of reflectors, the longest transport distance of sediments, and the thickest deposits in comparison to other dip directions—all recognized in this study and serving as typical characteristics for sedimentary unit identification and separation from the overlapped sedimentary complex. This study also summarizes diverse patterns—including collateral and prograding types—of sedimentary unit contact relationships and stage analysis along dip and strike directions. Collateral patterns are composed of three subtypes: superimposed, antithetic, and isolated. Three sedimentary units—S1, S2, and S3—are recognized in the study area. Summarized patterns of sedimentary unit contact relationships indicate that S1 was deposited earliest and S3 latest. The proposed patterns supplement seismic-based sedimentologic studies. This work may serve as a useful reference for sand-body characterization and stage analysis in other basins and similar areas.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Instead of using discrete values for properties that influence the volumetric calculation for recoverable reserves from the Middle Bakken, Pronghorn, and Three Forks reservoir rocks in the Williston Basin in North Dakota, an uncertainty-based assessment method was used. Various estimates have been published in the past that attempt to quantify recoverable reserves from the Bakken petroleum system. The Bakken–Three Forks trend is regarded as an unconventional tight oil play typical of a continuous-type basin-centered accumulation. However, production data reveal that areas are unequal and that certain regions stand out as sweet spots whereas others exhibit fairly high water cuts. This paper is based on 28 well models, which have been porosity-calibrated and adjusted for the prevalent thermal regime. The area of interest was delineated by geological parameters such as shale maturity and reservoir rock presence as well as existing production data. The purpose of this study is to use an uncertainty assessment method based on hundreds of basin model simulations that sample ranges of probable input parameters to quantify the recoverable reserves from the Bakken petroleum system in North Dakota. The results are displayed in reverse cumulative probability plots, tornado sensitivity charts, as well as in maps of the 10% chance, 50% chance (P50), 90% chance values. This means that there is an X% chance of success or an X probablity of realizing a certain amount of hydrocarbon. The P50 results of the uncertainty assessment indicate that approximately 4 billion bbl of oil and 3.6 tcf (102 billion m〈sup〉3〈/sup〉) of gas are recoverable from the Middle Bakken, Pronghorn, and Three Forks reservoir rocks in North Dakota. The Bakken–Three Forks trend appears to be an overcharged petroleum system, where the available pore space in reservoir rocks is the limiting factor for each accumulation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Węglówka oil field is located in the outer Carpathians. The outer Carpathians are a region where hydrocarbons were discovered and exploited at the end of the nineteenth century in several dozen oil fields, which are relatively small. The Węglówka oil field is one of the largest in this region. In the 150 yr or so of hydrocarbon exploration in the area, more than 1 million t (〉1,237,000 tons [〉8,841,000 bbl]) of oil have been produced. Hydrocarbons are concentrated in Lower Cretaceous sandstones (Grodziszcze and Lgota sandstones) that form an anticline sealed by Upper Cretaceous marls called the Węglówka marls. These cap rocks are up to 600 m (2000 ft) thick. Because of the thrust-related exhumation, they were exposed at the surface and represent the youngest deposits in the region. The present work is focused on a detailed petrographic characterization of the Węglówka marls. This study allows petroleum geologists to better understand the evolution of porosity in these cap rocks and can serve as a foundation for the prediction of their sealing properties. The marls appear as a succession of interbedded red and green varieties, which occur in up to 2-m (6-ft)-thick beds. These beds are nonarenaceous, soft, and bioturbated. Grain size corresponds to approximately 80% clay and less than 20% silt fractions. X-ray diffraction (XRD) reveals that the marls contain, on average, 54% clay, 28% calcite, 16% quartz, up to 3% feldspars and, in red marls, 3% hematite. The XRD patterns of clay are typical of mixed-layer illite–smectite ([I–S]; 40% illite in I–S). The clay structures are dioctahedral with similar octahedral Mg and relatively high Fe〈sup〉3〈/sup〉〈sup〉+〈/sup〉 contents both in the red and green intervals. As revealed by standard petrography combined with high-resolution petrography performed through the use of a field emission scanning electron microscope, the marls have mudstone textures according to Dunham’s (1962) classification and are mostly composed of coccoliths and clay with rare nanoquartz. This rock may be considered an impure chalk. Sealing properties of the Węglówka marls are indicated by the specific surface area, porosity, pore size, and permeability, calculated using N〈sub〉2〈/sub〉 gas adsorption, helium, and mercury porosimetry. The sealing potential is postulated to result from a combination of the following: (1) origin of components (i.e., deposition of minute calcareous bioclasts and volcanic material as a source for clay); (2) oxygenated sedimentary environment (as a result of the presence of oxygen in the sediments, burrowing caused the rocks to be homogenized); and (3) tectonic-induced clogging of pore space because of reorganization of clay flakes (the rocks were strongly tectonically deformed, which resulted in reduction of porosity in clay aggregates).〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Calcite cementation has been identified as an active process in the Upper Triassic Yanchang Formation throughout its burial history and as a major diagenetic factor causing strong reservoir heterogeneities. The origins of calcite cements and their relevance to reservoir heterogeneities were investigated using a suite of petrographic and geochemical methods, including optical microscopy with fluorescence and cathodoluminescence, scanning and backscattered electron microscopy with energy-dispersive spectrometry, x-ray diffraction, x-ray fluorescence, electron probe microanalysis, quantitative evaluation of minerals by scanning electron microscopy, fluid inclusion analysis, and carbon and oxygen stable isotope analyses. The sandstones are compositionally immature with relatively high amounts of volcanic rock fragments. The two generations of calcite cements are Ca-I and Ca-II. The Ca-I calcites are distributed along the interface of sandstone and mudstone units and were formed during the Late Triassic to Early Jurassic at formation temperatures of approximately 90°C. The Ca-II calcite mainly developed in the lower part of the fining-upward sandstone units and was formed in the Late Jurassic at higher temperatures of approximately 110°C. The origins of calcite cements were constrained by geochemical and isotope measurements, fluid inclusion homogenization temperature, and in situ element analysis. The Ca-I calcite cement originated from dissolution of the lacustrine depositional carbonates in the interbedded mudstones and reprecipitation in the adjacent sandstones. The Ca-II calcite was mainly related to organic matter decarboxylation, with Ca〈sup〉2+〈/sup〉 having been provided internally by volcanic fragment alteration and plagioclase dissolution. Calcite cementation had caused strong reservoir heterogeneities in the Yanchang Formation tight sandstones. The Ca-I calcite cementation destroyed reservoir properties along the interface of sandstones and mudstones. The lower parts of the fining-upward sandstone units were tightly cemented by Ca-II calcite, although they originally had high porosity and permeability. The middle–upper parts of the fining-upward sandstone units contain less calcite cements and thus have better preserved reservoir pores because of oil emplacement inhibiting the calcite cementation processes.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling shale gas field is located in a mountainous area, with well-developed underground rivers and karst caves. It also has a highly concentrated population, so the shale gas development in this field is faced with environmental protection problems. Combined with the characteristics of surface natural environment in the Fuling shale gas field and the features of shale gas development engineering, the main environmental issues encountered in the development of the Fuling shale gas field were analyzed. Studies on intensive land use, water conservation and protection, harmless use and disposal of oil-based drill cuttings, recycling of wastewater from drilling and fracturing, and green environment management mode for shale gas development were conducted, and the green development technology system suitable for the Fuling shale gas field was established. Field applications showed that, after applying the green development technology, the land occupation was reduced by 62.l%, the recycling rate of drilling and fracturing wastewater was up to 100%, the oil content of treated oil-based drill cuttings was less than 0.3%, and carbon dioxide emission was reduced by 64.47 × 10〈sup〉4〈/sup〉 t (1.41 × 10〈sup〉9〈/sup〉 lb). Thus, the goal of zero contamination was realized during shale gas field development. Research showed that the green and environmental protection development technology for the Fuling shale gas field has served as a valuable demonstration in the environmental protection in large-scale development of shale gas fields in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Increased oil and gas production in many areas has led to concerns over the effects these activities may be having on nearby groundwater quality. In this study, we determine the lateral and vertical extent of groundwater with less than 10,000 mg/L total dissolved solids near the Lost Hills–Belridge oil fields in northwestern Kern County, California, and document evidence of impacts by produced water disposal within the Tulare aquifer and overlying alluvium, the primary protected aquifers in the area.The depth at which groundwater salinity surpasses 10,000 mg/L ranges from 150 m (500 ft) in the northwestern part of the study area to 490–550 m (1600–1800 ft) in the south and east, respectively, as determined by geophysical log analysis and lab analysis of produced water samples. Comparison of logs from replacement wells with logs from their older counterparts shows relatively higher-resistivity intervals representing the vadose zone or fresher groundwater being replaced by intervals with much lower resistivity because of infiltration of brines from surface disposal ponds and injection of brines into disposal wells. The effect of the surface ponds is confined to the alluvial aquifer—the underlying Tulare aquifer is largely protected by a regional clay layer at the base of the alluvium. Sand layers affected by injection of produced waters in nearby disposal wells commonly exhibit log resistivity profiles that change from high resistivity in their upper parts to low resistivity near the base because of stratification by gravity segregation of the denser brines within each affected sand. The effects of produced water injection are mainly evident within the Tulare Formation and can be noted as far as 550 m (1800 ft) from the main group of disposal wells located along the east flank of South Belridge.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km〈sup〉2〈/sup〉 (10,000 mi〈sup〉2〈/sup〉). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity is one of the most important rock properties in describing hydrocarbon reservoirs. Tests on core samples provide direct and representative porosity data, and the measurement of porosity at high confining pressures is recognized to correlate well with subsurface reservoir porosity. Whereas theoretical deductions of the changes and relationships of pressures, volumes, and compressibility suggest that porosity is reduced during the coring and lifting processes, the porosity measurement at elevated confining pressure does not evaluate original reservoir porosity. This theory is quantitatively validated by repeated laboratory experiments of loading and unloading on sandstone core samples. When the in situ confining pressure is approximately 30–35 MPa (∼4350–5076 psi), coring and lifting would cause a porosity reduction of approximately 1.2%–1.6%, and the porosity test under high confining stress results in further porosity loss. A revised approach in calculating reservoir porosity from cored samples is proposed and can have significant implications for reserve calculations, recovery factors, and geostatistical reservoir models. The study is important for both conventional and unconventional reservoirs because it discusses a fundamental mechanism of porosity change.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In this paper, high-resolution three-dimensional seismic data are used to interpret a transpressional salt tectonic structure in the Yingxiongling area, Qaidam Basin, China. The geometries of the salt structure and the Shizigou fault system that intersects it are precisely depicted. The Shizigou fault system is composed of suprasalt and subsalt components. The suprasalt component is a Y-shaped reverse fault, and the subsalt component is a complex flower structure. In previous studies, suprasalt and subsalt components were interpreted as two independent fault systems. This paper proposes instead that the suprasalt and subsalt faults are kinematically related and decoupled across the salt layer.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum mobility in shale is closely correlated with the attributes of shale petroleum and pores; however, the relationship between these attributes is poorly understood. To characterize petroleum mobility in self-sourcing reservoirs, a suite of mature Eocene shales was selected and subjected to organic solvent extraction, and both the raw and solvent-treated samples were analyzed using pyrolysis, nitrogen adsorption, and x-ray diffraction. The results show that the pore surface area and pore volume of these shales are mainly controlled by their clay and quartz content rather than their organic matter (OM) content and are limited by the presence of carbonates. Correlations of soluble OM with pore surface area and volume after solvent extraction indicate that petroleum mobility of studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds are established in the studied area and should be similar for the self-sourcing reservoirs from similar sedimentary environments. This work proposes a method to reveal the thresholds of petroleum content and pore diameter for petroleum mobility in self-sourcing reservoirs, which is useful in the assessment of petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉For oil-rich shales, current solvent extraction– and thermal extraction–based methods inaccurately measure hydrocarbon-filled porosity (〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉). Moreover, the hydrocarbon composition is not characterized by either method. Here, we show how open-system programmed thermal extraction and pyrolysis, LECO total organic carbon, Archimedes bulk density, and helium pycnometry measurements are integrated to calculate oil and gas pore volumes, characterize their composition, and estimate mobility. Use of a modified multiramp, slow-heating thermal extract, and pyrolysis temperature program further subdivides the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. Saturate–aromatic–resin–asphaltene (SARA) separation and gas chromatography of solvent-extracted organic matter and thermally extracted oils are used to compositionally classify the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. The segregated bulk compositions of gas- and oil-filled porosity measured via this method are shown to overlap and are broken into the following categories: gas-filled porosity (∼C〈sub〉1〈/sub〉–C〈sub〉14〈/sub〉), light oil–filled porosity (∼C〈sub〉6〈/sub〉–C〈sub〉36〈/sub〉), and heavy oil–filled porosity (∼C〈sub〉32〈/sub〉–C〈sub〉36〈/sub〉+). Furthermore, slow-heating multiramp thermal extraction can subdivide the light oil–filled porosity into four components capturing the C〈sub〉11〈/sub〉–C〈sub〉13〈/sub〉, C〈sub〉12〈/sub〉–C〈sub〉16〈/sub〉, C〈sub〉14〈/sub〉–C〈sub〉20〈/sub〉, and C〈sub〉17〈/sub〉–C〈sub〉36〈/sub〉 ranges of the extractable organic matter. Analysis of solvent-extracted oils by SARA identifies abundant saturates and aromatics in the light oil–filled porosity and abundant resins and asphaltenes in the heavy oil–filled porosity. Low-maturity shales can be dominated by heavy (C〈sub〉32〈/sub〉+) oils rich in asphaltene and resin fractions not observed in the produced fluid. The ratios of SARA components in the C〈sub〉15〈/sub〉+ fraction of produced fluid and core extract can be used to better estimate the potentially mobile 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling gas field in Sichuan Basin, China, has produced greater than 1.5 × 10〈sup〉10〈/sup〉 m〈sup〉3〈/sup〉 (0.53 tcf) of natural gas from overmature Upper Ordovician Wufeng and lower Silurian Longmaxi shales. To systemically investigate the characteristics of wettability and connectivity and to understand the underlying causes of production behavior, we study five samples of Wufeng and Longmaxi shales with different total organic carbon contents and mineral compositions. Complementary approaches include mercury intrusion capillary pressure (MICP), contact angle measurement, spontaneous imbibition and saturated diffusion, and tracer (both nonsorbing and sorbing) migration mapped via laser ablation inductively coupled plasma mass spectrometry. According to measured contact angles and imbibition tests conducted on aqueous (deionized water and brine) and oleic (n-decane) phases, Wufeng and Longmaxi shales are strongly oil wet and moderately strong water wet. The lower boundary of estimated permeability obtained from n-decane imbibition can reach 137 nd, which is higher than the geometric mean permeability derived from the MICP method (5.5–68.8 nd). Effective diffusion coefficients of the Wufeng and Longmaxi shales are in the range of 10〈sup〉−13〈/sup〉 m〈sup〉2〈/sup〉/s (1.1 × 10〈sup〉−12〈/sup〉 ft〈sup〉2〈/sup〉/s). Tests of imbibition and saturated diffusion using tracer-containing brine show that concentrations of nanometer-sized tracers decrease rapidly (a factor of 〉10) over a migration distance of a few millimeters from the sample edge, suggesting the presence of poorly edge-connected water-wet pores. Sparsely connected hydrophilic pores, mixed wettability, and highly restricted pathways collectively contribute to the limited migration of nano-sized tracers, which probably results in the production behavior of initial steep decline and low overall recovery in the Fuling gas field.〈/span〉

Description: A reliable rock classification in a carbonate reservoir should take into account petrophysical, compositional, and elastic properties of the formation. However, depth-by-depth assessment of these properties is challenging because of the complex pore geometries and significant heterogeneity caused by diagenesis. Common rock-classification methods in carbonate formations do not incorporate the impact of both depositional and diagenetic modifications on rock properties. Furthermore, elastic properties, which control fracture propagation and the conductivity of fracture under closure stress, commonly are not accounted for in conventional rock-classification techniques. We apply an integrated rock-classification technique, based on both depositional and diagenetic effects that can ultimately enhance (1) assessment of petrophysical properties, (2) selection of candidates for fracture treatment, and (3) production in carbonate reservoirs. We apply the conductive and the elastic self-consistent approximation theories to estimate depth-by-depth volumetric concentration of interparticle (e.g., interconnected pore space) and intraparticle (e.g., vugs) pores, as well as elastic bulk and shear moduli, in the formation. This process takes into account the impact of shape and volumetric concentrations of rock components on electrical conductivity and elastic properties. We document a successful application of the introduced technique in two wells in the upper Leonardian carbonate interval of Veterans field in west Texas. The identified rock types were verified using thin-section images and core samples. We estimate elastic moduli as well as interparticle porosity with average relative errors of approximately 8% and 10% compared to the core measurements, respectively. Furthermore, the well-log-based estimates of permeability and water saturation are improved by approximately 50% and 20%, respectively, after considering rock classification. Finally, we explain that the fracture propagation failure in the second well (i.e., well B) could be the result of relatively lower Young’s modulus in the rock class corresponding to fracture locations.

Description: The mineralogical complexity of mudstone reservoirs has led to the increased usage of multimineral optimizing petrophysical models for estimating porosity, water, and hydrocarbon volumes. A key uncertainty in these models is the log response parameter assigned for each log equation related to each volumetric variable. Default parameter values are commonly used and often need to be modified by considering subjective local knowledge or intuition to achieve a result that is considered acceptable. This paper describes the methods developed at Chevron for calibration of mineral log response parameters using core data. Mineral log response parameters are controlled by the major and trace element chemistry of the individual minerals in the formation rock matrix. BestRock™ uses a nonlinear approach to optimize whole-rock chemistry with mineralogy to calculate individual mineral structural formulas and trace element associations from which certain log response parameters can then be calculated. Accurate quantitative phase analysis (QPA) to determine mineral content is a critical step in the process, which is achieved here by rigorous sample preparation methods and QPA by x-ray diffraction (QXRD). The QXRD in combination with whole-rock elemental analyses are processed using Chevron’s BestRock optimization software to provide refined quantities of the mineral species present in the formation, their structural formulas, and their predicted wireline log responses. Calibrated petrophysical models are built from the information obtained from the QXRD and BestRock results. The method described herein provides an independent and robust method for determining petrophysical parameters that is independent of the interpreter, quick to implement, and supported by quantitative measurements.

Description: Clay- and lithic-rich sandstones are difficult to characterize through uncored well sections in terms of their grain size, porosity, and mineralogy, all of which are required for assessing reservoir quality and production performance. This paper presents results from a study through one such interval and shows how a combination of different techniques can be used to better understand rock properties of complex reservoirs, thereby helping to reduce reservoir uncertainty. In this study, mean data from laser grain-size analysis are comparable to point-counted grain size, and both are considered as viable analytical methods. Automated quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN ® ) provides a further useful and consistent grain-size measurement that can be applied to both core and cuttings samples. The QEMSCAN has also proved to be a valuable technique in the mineralogical analysis of sandstones that are lithic, clay- and feldspar-rich, eliminating the subjective nature that is inherent with optical analysis. Results from the studied interval show that porosity measured by conventional core analysis (CA) and mercury injection capillary pressure (MICP) analysis are generally comparable with log-derived total porosity. Porosity measured from point-counting and QEMSCAN techniques is significantly lower than total porosity, with the QEMSCAN porosity locally equivalent to log-derived effective porosity. Both point-count and QEMSCAN porosities show better correlations with permeability ( $${r}^{2}=0.90$$ and 0.94, respectively) than total porosity values ( $${r}^{2}=0.81$$ and 0.60 CA and MICP, respectively), suggesting that they might provide a measure of effective porosity in high-quality reservoir rocks.

Description: 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 $${\mathrm{CO}}_{2}$$ and $${\mathrm{N}}_{2}$$ 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 $$( 〈 2\hbox{ \hspace{0.17em}\hspace{0.17em} }\mathrm{nm})$$ 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.

Description: 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 $$15\hbox{ \hspace{0.17em}\hspace{0.17em} }{\mathrm{km}}^{2}$$ ( $$5.8\hbox{ \hspace{0.17em}\hspace{0.17em} }{\mathrm{mi}}^{2}$$ ), 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 $$\delta ^{13}\mathrm{C}$$ (from +4 to +8) supports an interpreted $${\mathrm{CO}}_{2}$$ volcanic mantle source, whereas, the $$\delta ^{18}\mathrm{O}$$ (from –9 to –5) is in agreement with warm meteoric waters. The $$^{87}\mathrm{Sr}/^{86}\mathrm{Sr}$$ 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.

Description: The shale beds of the Khabour and Akkas Formations (Ordovician–Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at $${\mathrm{C}}_{16}\mbox{--}{\mathrm{C}}_{18}$$ , indicating marine algal organic matter. Rock-Eval $${T}_{\mathrm{max}}$$ and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Description: Significant amounts ( $$ 〉 150\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}/\mathrm{day}/\mathrm{well}$$ ) 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.

Description: 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.

Description: 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.

Description: This paper examines the discovery process in terms of changing exploration paradigms and describes a field discovered because of this change in mindset. Prior to the Umiak discovery all wells in the Mackenzie Delta had been drilled on structural highs. Reevaluation of two 30-yr-old dry holes along with existing two-dimensional (2-D) seismic data resulted in discovery of the Umiak gas field. This reappraisal led to recognition that a stratigraphic trap might exist between these two wells drilled in the early 1970s. The Kilagmiotak M-16 well contained 290 m (951 ft) of porous sandstone in the Eocene Taglu Formation, whereas the Umiak J-37 well, up dip and 11 km (6.8 mi) to the west, had no sandstone in the same interval. Examination of 2-D seismic lines found evidence of an updip sandstone pinchout beneath an angular unconformity on a tilted fault block. Strata in the tilted fault block below the unconformity contain strong amplitudes and flat spots. Interpretation of a subsequent three-dimensional (3-D) survey supported the play. A partnership of Alberta Energy Company (operator, now Encana), Anadarko, and Gulf Canada (now ConocoPhillips Canada) drilled the Umiak N-16 discovery well during 2004. Gas and some oil was found in gently dipping Eocene Taglu shoreface and delta front sandstones, and within gently folded foreset beds of the Eocene Richards Formation above a mid-Eocene unconformity. The Umiak N-05 appraisal well drilled a year later confirmed the discovery. Together these two wells delineate the fourth largest onshore gas accumulation on the Mackenzie Delta.

Description: 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.

Description: 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 $$^{228}\mathrm{Ra}/^{226}\mathrm{Ra}$$ and $$^{226}\mathrm{Ra}$$ 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 $${\delta }^{18}\mathrm{O}$$ values were observed in the produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The $${\delta }^{18}\mathrm{O}$$ 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 $$ 〈 50\%$$ of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

Description: One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide $$({\mathrm{scCO}}_{2})$$ injected in the repository overcomes the caprock sealing capacity, leaking of $${\mathrm{scCO}}_{2}$$ may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1)  texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2)  composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on $${\mathrm{scCO}}_{2}$$ maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant $${\mathrm{CO}}_{2}$$ stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of $${\mathrm{scCO}}_{2}$$ column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average $${\mathrm{scCO}}_{2}$$ column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of $${\mathrm{scCO}}_{2}$$ column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with $${\mathrm{scCO}}_{2}$$ retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.

Description: 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 ( $${T}_{\mathrm{se}}$$ ) (–2° to 0°) and negative shelf-edge aggradation to progradation ratios ( $$\mathrm{d}y/\mathrm{d}x$$ ) (–0.04 to 0) and associated progradational and downstepping stacking patterns with low clinoform relief ( $${R}_{\mathrm{c}}$$ ) (150–550 m [492–1804 ft]) and negative differential sedimentation on the shelf and basin ( $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ ) (–0.6 to 0); (2) slightly rising trajectories with moderate $${T}_{\mathrm{se}}$$ (0°–2°) and medium $$\mathrm{d}y/\mathrm{d}x$$ (0–0.04), and associated progradational and aggradational stacking patterns with intermediate $${R}_{\mathrm{c}}$$ (250–400 m [820–1312 ft]) and intermediate $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ (0–0.6); and (3) steeply rising trajectories with high $${T}_{\mathrm{se}}$$ (2°–6°) and high $$\mathrm{d}y/\mathrm{d}x$$ (0.04–0.10) and associated dominantly aggradational stacking patterns with high $${R}_{\mathrm{c}}$$ (350–650 m [1148–2132 ft]) and high $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ (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 $${T}_{\mathrm{se}}$$ , $$\mathrm{d}y/\mathrm{d}x$$ , $${R}_{\mathrm{c}}$$ , and $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ 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.

Description: Cementation of sandstone by minor late barite and sphalerite is widespread in the Scotian Basin at burial depths 〉2 km (〉1 mi), providing information on fluid flow in the basin. The texture and geochemistry of these minerals were analyzed by scanning electron microscopy and electron microprobe on samples from conventional core. Barite and sphalerite postdate silica and carbonate cementation, occurring in veins or occupying secondary porosity. They occur with diagenetic chlorite, kaolinite, pyrite, titania minerals, kutnohorite, and Mn-siderite. This study relates barite and sphalerite to the salt-tectonic evolution of the basin, based on seismic interpretation, and the thermal history of the basin, based on fluid inclusion studies. Barite is readily transported in basinal fluids 〉100°C (212°F), yet is consistently a very late diagenetic mineral. This implies that the source of Ba is because of the late diagenetic breakdown of K-feldspars at 2–3 km (1–2 mi) depth, which is confirmed by covariation of Ba and Rb in sandstones. Sulfur isotope data suggest that the $${\mathrm{SO}}_{4}^{2+}$$ was derived from Argo Formation evaporites that include 1%–7% anhydrite. Sphalerite is mobile only in saline formation water 〉140°C (〉284°F) and requires long-distance transport through sandstones with Zn-rich Fe-Ti oxides. Active detachment faults on salt welds provide potential pathways and a source of salt for migrating formation water. The particularities of source and transport of both barite and sphalerite allow the pathways of basinal fluids and their relationship to active salt tectonics to be inferred, providing indirect dating of the later stages of diagenetic paragenesis corresponding to times of hydrocarbon charge.

Description: Net fluid production and pressure data were gathered to estimate the amount of $${\mathrm{CO}}_{2}$$ storage space available and the potential for additional oil recovery using $${\mathrm{CO}}_{2}$$ -enhanced oil recovery (EOR) in the Phacoides sandstone, McKittrick oilfield, San Joaquin Valley, California. The Phacoides reservoir has produced 61.5 million reservoir barrels of fluid, a volume equivalent to the subsurface capacity of 9.8 million metric tons of $${\mathrm{CO}}_{2}$$ . Reservoir pressure changes with fluid production suggest that injecting 1 million metric tons of $${\mathrm{CO}}_{2}$$ may raise reservoir pressures by 2 MPa (255 psi). We assume that the sealing capacity of the reservoir for $${\mathrm{CO}}_{2}$$ injection is equivalent to the conditions controlling the original hydrocarbon accumulation. If injection pressures exceed this limit, the $${\mathrm{CO}}_{2}$$ could leak through the caprock, from aging wellbores or along faults in the reservoir. Faulting has compartmentalized the reservoir into six major blocks with varying degrees of hydraulic communication. Injection wells will be required within each sealed fault block, resulting in additional costs for implementing a carbon capture and sequestration (CCS) project. Through $${\mathrm{CO}}_{2}$$ -EOR, an additional 17 million bbl of oil may be recoverable, thereby offsetting the cost of carbon storage. This is equivalent to 1.4 million metric tons of additional storage space. However, assuming that none of the carbon is captured, combustion of this additional oil will add approximately 7 million metric tons of $${\mathrm{CO}}_{2}$$ to the atmosphere, negating the available storage space in the reservoir and resulting in a net carbon gain to the atmosphere of 700,000 metric tons.

Description: Ore grade is one of the primary variables controlling the economic recovery of bitumen from oil sands reservoirs, hence there is a need for fast and reliable quantification of total bitumen content (TBC). This is typically achieved through laboratory-based Dean-Stark analyses of drill core samples. However, this method is time and labor intensive and destructive to the core sample. Hyperspectral imaging is a remote sensing technique that can be defined as reflectance spectroscopy with a spatial context, where high-resolution digital imagery (~1 mm/pixel [0.04 in./pixel]) is acquired and reflectance measurements are collected in each pixel of the image. This study compares two hyperspectral models for the determination of TBC from imagery of both fresh and dry core samples. For three out of four suites of fresh core, TBC was predicted within ±1.5 wt. % of the Dean-Stark data with both spectral models achieving correlations of $${R}^{2} 〉 0.97$$ . For a fourth fresh core and the dry core, larger margins of error were found because of some instances of overestimation. Surface roughness because of uneven oil distribution and small-scale fracturing is a potential source of error in some of the spectral TBC results, particularly for the dry core. Producing results within minutes with the additional benefit of being nondestructive to the core sample, hyperspectral imaging shows great potential to become a viable alternative method for bitumen content determination in oil sands.

Description: Many $${\mathrm{CO}}_{2}$$ -rich (up to 97% by volume) natural gas pools have been found in the continental margin basins of the northern South China Sea. By combining the geochemical data from 53 samples with their geologic backgrounds, this study investigated the origins and accumulation mechanism of $${\mathrm{CO}}_{2}$$ , and discussed the role of $${\mathrm{CO}}_{2}$$ in driving oil as it charged the reservoirs. The results reveal that the $${\mathrm{CO}}_{2}$$ gases in the Yinggehai basin originate mainly from the thermal decomposition of both Miocene calcareous shales and Paleozoic carbonates, and that $${\mathrm{CO}}_{2}$$ from mantle degassing is only a minor contributor. The $${\mathrm{CO}}_{2}$$ accumulations in the Yinggehai basin are mainly controlled by diapiric faults and episodic thermal fluid movements. The $${\mathrm{CO}}_{2}$$ gases in the eastern Qiongdongnan and western Pearl River Mouth basins are mainly related to magmatic or mantle degassing, and the volatiles from magmatic degassing during the igneous intrusion stage are the most likely major source of $${\mathrm{CO}}_{2}$$ in these reservoirs, with basement faults providing pathways for upward migration of $${\mathrm{CO}}_{2}$$ -rich mantle fluids. Natural displacements of oil by $${\mathrm{CO}}_{2}$$ appear to be common in the eastern Qiongdongnan and western Pearl River Mouth basins. The $${\mathrm{CO}}_{2}$$ -flooded oil or gas reservoirs have two common features that the present $${\mathrm{CO}}_{2}$$ gas pools or oil-bearing structures have residual oils representing prior charge, and are close to the basement faults that provide pathways along which the mantle-derived $${\mathrm{CO}}_{2}$$ -rich gas was migrated. The oils from prior hydrocarbon reservoirs have been naturally driven out by $${\mathrm{CO}}_{2}$$ to form secondary oil reservoirs in the eastern Qiongdongnan and western Pearl River Mouth basins. Therefore, a full understanding of the origin and distribution of $${\mathrm{CO}}_{2}$$ cannot just be used to trace hydrocarbon migration pathways, but also provide useful information for risk assessment prior to drilling.

Description: It has been suggested by some that methane contamination of water wells is the main negative consequence of the development of natural gas resources. Concurrently, speculation in academic white papers and in the press that methane may be toxic has resulted in public concern. In northern Pennsylvania, methane being released from groundwater and entering homes (so-called stray gas) has become a focus of this concern. This phenomenon was widespread decades before shale gas development was initiated. This paper reviews the available literature on the safety and health hazards associated with natural gas. It concludes that the risks to homeowners are highest from flash fires occurring in methane oxygen gas clouds at relatively low methane concentrations collecting in poorly ventilated, confined areas of houses such as basements. Such risks can be mitigated effectively and in most cases at minimal cost. Methane can result in death from hypoxia (lack of oxygen) but only at methane levels in the air of more than 60%, which are unlikely to develop except under exceptional circumstances. There is no evidence that low to moderate levels of exposure to methane in air have any toxic effect on humans, and evidence for such effects at very high levels (already fatal because of hypoxia) is equivocal. It seems likely that methane at concentrations at least as high as 2.5% may well have positive health benefits for some diseases.

Description: Micropores can constitute up to 100% of the total porosity within carbonate-hosted hydrocarbon reservoirs, usually existing within micritic fabrics. Here, three-dimensional computational representations of end-point micritic fabrics are produced using a flexible, object-based algorithm to further our understanding of the contribution that micropores make to flow. By methodically altering model parameters, we explore the state space of microporous carbonates, quantifying single and multiphase flow using lattice-Boltzmann and network models. In purely micritic fabrics, average pore radius (ranging from 0.26 to 0.44 μm) was found to have a positive correlation with single-phase permeability (1.7 to 2.7 md, respectively). Similarly, increasing average pore size resulted in decreasing residual oil saturation under both water-wet and 50% fractionally oil-wet states. Permeability was found to increase by an order of magnitude (from 0.6 to 7.5 md) within fabrics of varying total matrix porosity (from 18% to 35%) because of increasing pore size (0.37 to 0.56 μm, respectively), but minimal effect on multiphase flow was observed. Increased pore size due to micrite rounding notably increases permeability in comparison with original rhombic fabrics with the same porosity, but multiphase flow properties are unaffected. Finally, when moldic mesopores are added to a micritic matrix, they impact flow when directly connected. Otherwise, micropores control single-phase permeability magnitude. Importantly, recovery is dependent on both wetting scenario and pore-network homogeneity: under water-wet imbibition, increasing proportions of microporosity yield lower residual oil saturations. Together, these results quantify the importance of micropores in contributing to, or controlling, overall flow and sweep characteristics in such fabrics.

Description: Coal rank reflects the temperature of coalification, with higher rank coal forming at higher temperatures. If the temperature of coalification depended only on the Earth’s geothermal gradient, then the maximum rank of coal in a sedimentary basin should be directly proportional to the thickness of strata above the coal. This association does not occur in the Illinois Basin, a continental-interior basin in the midwestern United States, where the overall coal rank observed is higher than can be explained by past burial depth alone. Recognition of this anomaly has led many authors to suggest that hot groundwater flowing from south to north, during a Paleozoic basin-scale groundwater-migration event, increased coal rank. We analyzed vitrinite reflectance $$({R}_{\mathrm{o}})$$ , a measure of rank, as a function of depth in wells across the basin to determine how paleogeotherms, representing variation in temperature with depth, change with location. Our results show that the basin can be divided into three zones: (1) in the southern zone, the paleogeotherm varies irregularly with depth in strata above the sub-Absaroka unconformity (the contact separating Pennsylvanian and Mississippian strata); (2) in the central zone, the paleogeotherm displays a distinct inflection at the unconformity, for the rate of increase in $${R}_{\mathrm{o}}$$ with depth is greater above the unconformity than below the unconformity; and (3) the observed inflection in the paleogeotherm dies out northward, until, in the northern zone, the paleogeotherm has the same slope both above and below the unconformity. We propose that the inflection in the paleogeotherm of the central zone indicates that the hot groundwater responsible for causing an increase in coal rank flowed through a high-permeability zone just below the sub-Absaroka unconformity. This flow, which advected heat into Pennsylvanian strata above, cooled as it moved northward, so it did not influence the paleogeotherm in the northern zone. Preliminary studies of vein paragenesis, stable-isotope composition, and fluid-inclusions, as well as computer modeling of flow-related heat advection, support this proposal.

Description: This multidisciplinary study evaluates the structural and hydrogeologic evolution of Cretaceous-age reservoirs in the Putumayo basin, Colombia. We focused on the Eastern Cordillera fold-thrust belt along the southern Garzón Massif. Many important hydrocarbon accumulations occurred regionally along the proximal foreland basin and frontal fold-thrust belt defining the eastern margin of the northern Andes. To understand why recent Putumayo basin and adjacent thrust belt exploration has resulted in a wide range of oil quality and limited economic discoveries, we reconstructed the structural evolution, timing of oil migration, and timing of groundwater infiltration by (1) assessing regional trends in formation water, oil, and reservoir properties; (2) quantifying the timing of hydrocarbon generation and migration relative to trap formation using (a) two-dimensional (2-D) and three-dimensional seismic data to define and constrain a restorable balanced cross section from the Upper Magdalena Valley to the Putumayo foreland and (b) coupled one-dimensional thermal basin modeling; (3) evaluating the potential roles of Mesozoic extensional faulting and Paleogene shortening in the generation and preservation of structural traps; and (4) assessing groundwater influx from the modern foothills into the reservoir using a 2-D numerical groundwater flow model. We suggest that four-way closure is limited in the study area, where most foreland-verging structures create three-way fault closures that do not effectively trap light hydrocarbons. In addition, east-dipping structures and a relatively large reservoir outcrop area provide water infiltration pathways. Groundwater modeling suggests reservoirs were water washed by 2–200 million pore volumes since Andean uplift. Finally, average reservoir temperatures are 〈80°C (〈176°F), which further facilitated biodegradation.

Description: Potentiometric surfaces for Paleozoic strata, based on water well levels and selected drill-stem tests, reveal the control on hydraulic head exerted by outcrops in eastern Kansas and Oklahoma. From outcrop in the east, the westward climb of hydraulic head is much less than that of the land surface, with heads falling so far below land surface that the pressure:depth ratio in eastern Colorado is less than 5.7 kPa/m (0.25 psi/ft). Permian evaporites separate the Paleozoic hydrogeologic units from a Lower Cretaceous (Dakota Group) aquifer, and a highly saline brine plume pervading Paleozoic units in central Kansas and Oklahoma is attributed to dissolution of Permian halite. Underpressure also exists in the Lower Cretaceous hydrogeologic unit in the Denver Basin, which is hydrologically separate from the Paleozoic units. The data used to construct the seven potentiometric surfaces were also used to construct seven maps of pressure:depth ratio. These latter maps are a function of the differences among hydraulic head, land-surface elevation, and formation elevation. As a consequence, maps of pressure:depth ratio reflect the interplay of three topologies that evolved independently with time. As underpressure developed, gas migrated in response to the changing pressure regime, most notably filling the Hugoton gas field in southwestern Kansas. The timing of underpressure development was determined by the timing of outcrop exposure and tilting of the Great Plains. Explorationists in western Kansas and eastern Colorado should not be surprised if a reservoir is underpressured; rather, they should be surprised if it is not.

Description: 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.

Description: 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.

Description: There is a common belief that we can expect to add value to a prospect or prospect portfolio by improving the prospect chance of success (Pg) as a consequence of acquiring information and doing work. Established laws of probability dictate that this is incorrect. We do expect new information to add value to the exploration cycle, but not by an expectation of improving the prospect risk. New information may result in an increase or a decrease of Pg, but the expected result (the average of all possible outcomes) is zero change. Moreover, for a typical exploration prospect (Pg 〈 0.5), we expect that new information will downgrade more prospects Pg than are upgraded. Real-world prospect data are neither suitable nor publically available to study this. Instead, the concept is explored using an analogous process (prenatal prediction of fetus gender) for which good statistics exist, and by creating a synthetic prospect that can be analyzed in a repeatable way. The results support the predictions made above.

Description: 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.

Description: The exploitation of hydrocarbon reserves in naturally fractured reservoirs composed of different types of rocks has drawn considerable attention from the fracture characterization research community because of the importance of fractures to the prediction of fluid flow. One of the most common methods for rapidly analyzing fracture features is the scanline technique, which provides an estimate of fracture density and frequency. Despite the confidence provided by the systematic use of this method, errors and uncertainties caused by sampling biases exist. The problems caused by these uncertainties can detrimentally affect the construction of a computational model due to misleading trends. This study evaluated the uncertainty caused by sampling biases in the scanline data of opening-mode fractures in outcrops of naturally fractured Aptian laminated limestone from the Crato Formation, Araripe Basin, northeastern Brazil. The Monte Carlo method was chosen to introduce random values into the sampled values, which enabled us to verify the importance of errors in the accuracy of the method of representing the fracture network. In this study, errors and uncertainties were grouped into one parameter, termed the coefficient of uncertainty, which was defined as the ratio between the uncertainties, created by the errors and artifacts introduced artificially, and the original scanline data. The propagation of errors and uncertainties in the scanline data to the coefficients of the corresponding power law were determined. This evaluation can be applied in the construction of more reliable geomechanical models using analog geological models for naturally fractured reservoirs.

Description: Characterizing natural fracture systems involves understanding fracture types (faults, joints, and veins), patterns (orientations, sets, and spacing within sets), size distributions (penetration across layering, aperture, and trace length), and timing relationships. Traditionally, observation-based relationships to lithology, mechanical stratigraphy, bed thickness, structural position, failure mode, and stress history have been proposed for predicting fracture spacing along with the relative abundance of opening-mode fracture versus faults in fractured rocks. Developing a conceptual fracture model from these relationships can be a useful process to help predict deformation in a fractured reservoir or other fractured rock systems. A major pitfall when developing these models is using assumptions based on general relationships that are often site specific rather than universal. In this paper, we examine a mixed carbonate-shale sequence that is cut by a seismic-scale normal fault where fracture attributes do not follow commonly reported fracture relationships. Specifically, we find (1) no clear relationship between frequency (or spacing) of opening-mode fractures (joints and veins) and proximity to the main fault trace and (2) no detectable relationship between fracture spacing and bed thickness. However, we did find that (1) the frequency of small-displacement faults is strongly and positively correlated with proximity to the main fault trace, (2) fracture networks change pattern and failure mode (extension versus shear fracture) from pavement to pavement through the mechanically layered stratigraphic section, and (3) faults are more abundant than opening-mode fractures in many areas within the fracture network. We interpret that the major fracturing initiated near maximum burial under relatively high-differential stress conditions where shear failure dominated and that mode-1 extension fracturing occurred later under lower differential stress conditions, filling in between earlier formed shear fractures. We conclude that whenever possible, site-specific observations need to be carefully analyzed prior to developing fracture models and perhaps a different set of fracture network rules apply in rocks where shear failure dominates and mechanical stratigraphy influences deformation.

Description: Thousands of shale gas wells have been drilled and hydraulically fractured across the state of Pennsylvania over the past decade, and more wells are being drilled each year. The drilled lengths of these wells and the amount of water being used to hydraulically fracture (frac) them continue to increase. These increases have led to an increase in the volume of wastewater being produced each year. However, the ratio of energy produced per barrel of wastewater has increased significantly over the past six years. Recent data show the volume of wastewater produced in one year is approximately 20% of the volume of frac water used in that same year. With changes in state policies, drilling companies in Pennsylvania have been recycling most of their wastewaters over the past few years. The development of various treatment technologies and brine-resistant frac mixtures has allowed companies to recycle this wastewater for use in future frac jobs. Use of this recycled water does not appear to be having a significant effect on production of oil or gas from wells. Recycling wastewater can be very cost-competitive when compared to options such as disposal via waste-treatment plants or injection wells.

Description: Shale gas development in the United States has revolutionized energy production and supply, making the nation energy independent for the first time in decades. However, many people remain concerned that the large-scale hydraulic fracturing necessary to recover hydrocarbons from shale may degrade the environment, including groundwater. Improving the understanding of how groundwater may be impacted by shale gas development requires field monitoring at multiple sites on different shale plays under a variety of climates and hydrologic conditions. Such monitoring has been difficult to achieve because of a lack of access to commercial sites and an absence of funding to drill dedicated research wells.

Description: Many different rock intervals are used for brine disposal injection in the Appalachian Basin. The study area was defined as eastern Kentucky, Ohio, Pennsylvania, and West Virginia. Brine injection in the study area has increased from approximately 6–7 million barrels (bbl) per year in the early 2000s to 17.6 million bbl in 2012, mostly due to shale gas activity. A review of geologic properties and subsurface distribution of rock formations used for injection is useful to understand brine disposal operations in the region. Operational data on injection rates and pressures were compiled for 2008–2012 for more than 300 class II brine disposal wells. Several class II brine disposal wells were monitored with continuous wellhead pressure loggers to estimate reservoir properties and understand injection operations. Project results provide a catalog of injection rates for the various formations, which range from hundreds to more than 100,000 bbl per month per well. Hydrologic analysis of depleted hydrocarbon reservoirs and deep saline formations in the study area indicates that there is a large capacity for brine disposal, but the characteristics of the rock formations may limit injection rates. Based on hydrocarbon production and brine injection volumes from 2008 to 2012, approximately 9984 bbl of brine were routed to class II brine disposal wells per billion cubic feet gas production, which suggests ultimate demand of up to 706–2290 million bbl brine disposal related to unconventional Marcellus and Utica plays. Understanding the geology and operational history of the injection zones is critical to support safe, reliable, and environmentally responsible brine disposal in the region.

Description: Disposal of the liquid wastes generated during extraction of unconventional oil and gas resources in North America is increasingly becoming a constraint to development. Currently, the bulk of these wastes is disposed of by injection into deep bedrock formations. In certain development areas, the presence of suitable disposal formations is scarce, or disposal operations are difficult to site given area constraints. To address this challenge, a process of identifying high-value disposal targets (i.e., formations and locations) was developed using a combination of hydrogeological principles, multicriteria analysis, and geospatial mapping. This paper outlines the process developed to identify potential disposal targets to support oil sand development in Alberta and the results obtained.

Description: 〈span〉〈div〉ABSTRACT〈/div〉The upper zone of the Lower Cretaceous Kharaib Formation (151–177 ft [46–54 m] thick in the studied wells) is a major oil reservoir in several giant oil fields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oil field.Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity losses in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) within the upper and lower 12–17 ft (4–5 m) of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level. Most (95%) of porosity-permeability data from the studied wells lie within Lucia rock-fabric class 3, showing distinct but relatively subtle differences between texture groups, whereas a subordinate part of the data from the upper, relatively mud-poor third of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of the following: (1) a diagenetic model for porosity controls; (2) the use of a modestly higher porosity-permeability transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3); and (3) a recognition of the scattered and widely varying occurrences of exceptionally high permeabilities in the upper reservoir.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow.Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference.The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal conductivity is a major influencing factor on subsurface conductive heat transport and resulting temperature distribution, which in turn is a key parameter in basin modeling. Basin modeling studies commonly use representative literature values of thermal conductivity despite their impact on modeling results. We introduce a workflow for quantifying the effect of uncertain thermal conductivity on subsurface temperature distribution and thus on basin modeling results and test this workflow on a two-dimensional generic model from the Nordkapp Basin; a prior ensemble of possible models is conditioned according to Bayes’ theorem to incorporate prior knowledge of temperature data. This conditional probability yields a posterior ensemble of temperature fields with a significantly reduced standard deviation. To verify our approach, we use five characteristic scenarios from the posterior ensemble for transient petroleum systems modeling. How considering uncertain thermal conductivity affects variance in hydrocarbon generation is assessed by modeling corresponding vitrinite reflectances (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉).Temperature uncertainty increases with depth. It also increases with increasing offset from the salt diapirs, which can be associated with a large lateral heat-flow component in the complex tectonic environment of the Nordkapp Basin. The introduced workflow can reduce temperature uncertainty significantly, especially in regions with high prior uncertainty. The 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 is very sensitive to changes in thermal conductivity because the onset depth of the gas window in the Nordkapp Basin may vary by up to 800 m (2600 ft) within the 95% confidence interval. This demonstrates the importance of quantification of the uncertainty in thermal conductivity on thermal basin modeling.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Yinggehai–Song Hong Basin has received a large amount of terrigenous sediment from different continental blocks since the Paleogene. The Yingdong slope, which is located on the eastern side of this basin, is an important potential gas province, but the provenance of the marine sediments in this area are poorly understood. The detrital zircon U-Pb geochronology of sedimentary rocks from the lower Miocene to Quaternary is examined in this study to investigate the temporal and spatial variations in provenance since the early Miocene. The U-Pb ages of detrital zircon range from 3078 to 30 Ma, suggesting that sediment input is derived from multiple sources. Detailed analyses of these components indicate that both the Red River and Hainan are likely the major sources of the sediments on the Yingdong slope, with additional minor contributions from central Vietnam (eastern Indochina block) and possibly the Songpan–Garze block. Variations in the dominant detrital zircon populations within stratigraphic successions display an increasing contribution from the Red River since the middle Miocene. This resulted from the progradation of the Red River Delta in the northern basin and may have also been influenced by regional surface uplift and associated climate changes in East Asia. This study shows that the Red River has had a relatively stable provenance since at least the early Miocene, indicating that any large-scale drainage capture of the Red River should have occurred before circa 23 Ma.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Jurassic black mudstone and coal beds in the central Junggar Basin, northwestern China, are the major source rocks for the basin with type II〈sub〉2〈/sub〉 and type III (gas-prone) kerogens. Widespread overpressures are developed in the Jurassic stratigraphic interval. Sonic and resistivity logs display strong characteristic responses of overpressure in the mudstones, with anomalously high acoustic traveltimes and low resistivity compared with the normally pressured mudstones. The overpressured Jurassic sediment sequences appear to have undergone normal compaction because the mudstones exhibit no anomalously low bulk density. The overpressured mudstones deviate from the normally pressured mudstones in density–effective vertical stress space. The overpressure in the Jurassic source rocks is, therefore, not caused by disequilibrium compaction. The overpressured Jurassic sandstone reservoirs are predominantly oil and gas saturated or oil bearing. The well-log responses of the overpressured mudstones and seismic velocity characteristics indicate that the top depth of the overpressure zone ranges from 3800 to 4600 m (12,500 to 15,100 ft), corresponding to formation temperatures of approximately 94°C to 111°C (∼201°F to 232°F), with estimated vitrinite reflectance values of 0.6% to 0.75%. The Jurassic source rocks with overpressure are capable of generating hydrocarban at present and are currently overpressured. All the evidence suggests that the overpressure in the Jurassic source rocks in the central Junggar Basin is caused by hydrocarbon (HC) generation. The overpressure evolution was modeled quantitatively in response to pressure changes caused by HC generation during basin evolution. The results indicate that multiple episodes of overpressure development and release occurred within the Jurassic source rocks, suggesting multiple episodes of HC expulsion. The timing and numbers of these episodes of HC expulsion were thus determined from the modeled overpressure evolution.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal properties of rocks are essential parameters for investigating the geothermal regime of sedimentary basins, and they are also important factors in assessments of hydrocarbon and geothermal energy resources. The Tarim Basin, the largest basin located in the north of the Tibetan Plateau, northwestern China, has great hydrocarbon resource potential and is an ongoing target for industry exploration. However, the thermal properties of sedimentary rocks within the basin are yet to be systematically investigated at a basin scale, thereby limiting our understanding of the thermal regime in the basin. Here, we collected 101 samples of sedimentary rocks and measured their thermal properties. Our results show that the ranges (and means) of thermal conductivity, radiogenic heat production, and specific heat capacity are 1.08–5.35 W/mK (2.52 ± 0.99 W/mK), 0.03–3.24 μW/m〈sup〉3〈/sup〉 (1.24 ± 0.87 μW/m〈sup〉3〈/sup〉), and 0.75–1.10 kJ/(kg·°C) (0.87 ± 0.07 kJ/(kg·°C)), respectively. Volumetric heat capacity and thermal diffusivity at the temperature of 40°C range from 1.61 to 2.79 MJ/(m〈sup〉3〈/sup〉·K) (2.26 ± 0.25 MJ/[m〈sup〉3〈/sup〉·K]) and 0.44–2.95 × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s ((1.12 ± 0.53) × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s), respectively. The thermal properties vary considerably for different lithologies, even within the same lithotype, indicating that thermal properties alone cannot be used to distinguish lithology. Thermal conductivity increases with increased burial depth, density, and stratigraphic age, suggesting the dominant influence is porosity variation on thermal conductivity. Furthermore, a strong contrast in the thermal properties of rock salt and other sedimentary rocks perturbs the geothermal pattern, which should be taken into consideration when performing basin modeling.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The relationship between base metal deposits, especially Mississippi Valley–type (MVT) Pb–Zn deposits, and hydrocarbons is not well constrained. This is despite the fact that hydrocarbons generally occur in MVT deposits; the ores are emplaced in the same temperature range as hydrocarbon maturation and migration, and the deposits commonly occur in proximity to metal-rich black shales. Better understanding should lead to better exploration models for both hydrocarbons and MVT deposits. This connection is better understood with the help of Pb isotope patterns. Sphalerite Pb isotope compositions from the northern Arkansas and Tri-State mining districts and Woodford–Chattanooga and Fayetteville Shales were determined to assess the potential of shales as source rocks for the ore metals. The ores in both districts have a broad range of Pb isotope ratios and define linear trends, suggesting mixing of Pb from two distinct end members. Current results and previous depositional environment studies indicate the following: (1) shales deposited mainly under nonsulfidic anoxic conditions represent the less radiogenic end member, or (2) shales are the only source of ore metals. Given the array of organic molecules, each with their own thermochemical range, and the ways metals can be associated with them, the release of metals may cover varying ranges. Thus, the compositions of the released fluids would change through time and not have a single static composition, closely approximating the isotopic composition of the released metals at various times. Mineralization derived from a dynamically evolving fluid may show apparent end members, without the need to call on mixing of fluids from separate sources.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A subaqueous clinoform system has been identified from high-quality three-dimensional seismic data from the northeast Exmouth Plateau, North West Shelf, Australia, and was interpreted as a shelf–slope–basin clinoformal component of a Jurassic fluviodeltaic system (the Legendre delta). Several geomorphological features associated with shelf-slope development and subsequent rift tectonics were identified, including (1) submarine channels at slope to basin floor; (2) gullies on the slope; (3) slumps on the shelf; and (4) canyons, canyon-derived gravity flow deposits, and a fan lobe developed in subsequent rift processes.The results of this study provide insights into the controlling factors on the sinuosity, degree of erosion, and sediment gravity flows of channels developed at slope to basin-floor settings, which shed light on the way fluvial sands were transported across the shelf and slope to the basin floor. The geometries and distributions of gravity flow deposits, if confirmed by drilling, may serve as an analog for reservoir prediction in the deep-water fluviodeltaic settings. The gullies on the slope were interpreted as a result of dilute, sheetlike flows. The slumps on the shelf were interpreted as a result of nonslope-related causes.The syntectonic canyons, the canyon-derived gravity flow deposits, and the fan lobe present vivid examples of the erosion and sedimentation processes during active rift tectonics and have significant implications for understanding the rift processes of the North West Shelf, Australia, as well as other rift-related basins.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Giant petroleum accumulations worldwide with burial depths more than 7000 m (〉23,000 ft) occur mostly in Mesozoic and Cenozoic reservoirs and yield predominantly natural gas. Recently, however, a giant oil accumulation with reservoir depths between 7000 m (23,000 ft) and 8000 m (26,000 ft) was discovered in the lower Paleozoic section in the southern part of the Halahatang region in the Tarim Basin, China. Petroleum sourced from lower Paleozoic rocks is contained in Ordovician karst fracture-cave reservoirs and sealed by Middle–Upper Ordovician limestones and mudstones. The newly discovered superdeep accumulation is among the deepest black single-phase oil accumulations worldwide and opens up new avenues for petroleum exploration in deep-marine carbonate reservoirs. Reservoir pressures are between 75 MPa (10,878 psi) and 85 MPa (12,328 psi), with pressure coefficients between 1.2 and 1.7 and temperatures ranging between 140°C (284°F) and 172°C (342°F). Charging and accumulation of petroleum occurred during the late Hercynian orogeny, followed by subsequent gradual deep burial, which took place before rapid subsidence beginning circa 5 Ma. Following subsidence, the thickness of overlying strata increased by more than 2000 m (〉6600 ft) before finally attaining current depth. Therefore, this oil accumulation represents a well-preserved ancient petroleum system. Based on the geochemical features of oils and gases, the crude oils can be classified as mature, sourced from mixed marine organofacies of shale, marl, and carbonate, whereas the gases were cogenerated with oils. Despite very high present-day reservoir temperatures, no oil cracking has occurred because of the relatively short exposure of oils to high temperatures in a low geothermal gradient regime. Thus, there is significant exploration potential under similar conditions for liquid petroleum in superdeep strata. Faults and reservoirs are major factors controlling petroleum accumulation. Interlayer karsts with excellent fracture-cavity connectivity developed adjacent to faults, generally resulting in the enrichment of oil and gas along fault zones. High-quality reservoirs in this area are easy to identify because they exhibit strong bead-like amplitude features in seismic sections. Wells located near faults produce relatively large amounts of oil and gas. Effective karst fracture-cave reservoirs with noncracked oil may exist below 8000 m (26,000 ft) in the Tarim Basin and represent a significant exploration target in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Substantial amounts of petroleum were recently discovered in the Carboniferous andesite, tuff, breccia, and basalt reservoirs of the Chepaizi uplift in the western Junggar Basin. However, the charging history of the Carboniferous petroleum reservoir is poorly understood. Oil–oil correlation studies indicate that all of the oils were mainly derived from the middle Permian Wuerhe Formation source rocks, possibly mixed with a small contribution from Carboniferous Baogutu Formation source rocks in the neighboring Changji sag. Based on the petrographic and microthermometry of fluid inclusions, two hydrocarbon charging episodes are defined; these episodes were characterized by a low-peak-range homogenization temperature (〈span〉Th〈/span〉) distribution (80°C–90°C) and high salinity (13.22–13.42 wt. % NaCl) and a high-peak-range 〈span〉Th〈/span〉 distribution (120°C–130°C) and low salinity (4.89–11.72 wt. % NaCl), respectively. Through one-dimensional basin modeling and pressure–volume–temperature–composition simulation, the burial-thermal histories for wells P61, P66, P668, and P663 were reconstructed, and their trapping temperatures of the hydrocarbon inclusions were calculated to be higher than their corresponding highest paleotemperature (i.e., 56.8°C, 53.7°C, 60.9°C, and 58.1°C, respectively), implying fast hydrocarbon charging processes promoted by deep hydrothermal fluids. Associated with the hydrocarbon generation history, sealing process of the Hongche fault, and regional tectonic evolution, these two hydrocarbon charging events were deduced as the adjustments of oils previously accumulated along the Hongche fault zone, because of the tectonic extension in the Paleogene and regional tilting in the Neogene, respectively. The general direction of oil charging was traced from south to north and from east to west, as indicated by the molecular parameters of nitrogen-bearing compounds and C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 triaromatic steroids/C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 + C〈sub〉26〈/sub〉–C〈sub〉28〈/sub〉 triaromatic steroids (TA(I)/TA(I+II)), which roughly coincided with the active fracturing.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Modern oil and gas seismic surveys commonly use areal arrays that record continuously, and thus routinely collect “excess” data that are not needed for the conventional common reflection point imaging that is the primary goal of exploration. These excess data have recently been recognized to have utility not only in resource exploration but also for addressing a diverse range of scientific issues.Here we report processing of such discarded data from recent exploration surveys carried out in southeastern New Mexico. These have been used to produce new three-dimensional (3-D) seismic reflection imagery of a layered complex within the crystalline basement as well as elements of the underlying crust. This enigmatic basement layering is similar to that found on industry and academic seismic reflection surveys at many sites in the central United States. Correlation of these reflectors with similar features encountered by drilling in northwestern Texas suggest that they may be part of an extensive, continental-scale network of tabular mafic intrusions linked to Keweenawan rifting of the igneous eastcentral Unites States during the late Proterozoic. More importantly, this analysis clearly demonstrates that the new generation of continuously recorded 3-D exploration datasets represent a valuable source of fresh information on basement structure that should be examined rather than discarded. Such basement information is not only important to understanding crustal evolution, it is directly relevant to assessing risks associated with fossil fuel extractions, such as induced seismicity related to waste water injection.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The detailed depositional systems and basin evolution of Lower Cretaceous coal-bearing strata in the Erlian Basin of northeastern China were analyzed based on extensive borehole and outcrop data. A total of 7 facies associations are interpreted and consist of 14 distinct lithofacies, with lithologies including conglomerates, sandstones, siltstones, mudstones, shales, and coals. Five third-order sequences were recognized, and their internal lowstand, transgressive, and highstand systems tracts were defined based on six key sequence stratigraphic boundaries. These boundaries were represented by regional unconformities, basal erosional surfaces of incised valley fills, interfluvial paleosols, and abrupt depositional facies-reversal surfaces. Sequences I–V correspond to the rift-initiation stage, the early-rift climax stage, the late-rift climax stage, the immediate postrift stage, and the late postrift stage of the basin, respectively. The preferred sites for coal accumulation were braided fluvial delta plain, meandering fluvial delta plain, and littoral–shallow lake environments. The major coal seams formed during the early and late transgressive systems tract of sequences III, IV, and V, which were well developed in the eastern, northeastern, and northeastern parts of the Erlian Basin, respectively. Three coal depositional models were summarized in the sequence stratigraphic framework, including types 1, 2, and 3, corresponding to the Newark type, Newark–Richmond type, and Richmond type, respectively. These coal depositional models were closely related to the basin evolution. These results could provide preferred depositional environments and favorable areas of coal and coalbed methane (CBM) for the exploration and development of coal and CBM in the Erlian Basin, with the Jiergalangtu, Huolinhe, Baiyinhua, and A’nan sags recommended as the key sags.〈/span〉

Description: 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.

Description: 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 ( $${S}_{\mathrm{Hmax}}$$ ) 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 $${\mathrm{CO}}_{2}$$ injection and production wells oriented along interpreted compartment boundaries at high angles to $${S}_{\mathrm{Hmax}}$$ . This combination of $${\mathrm{CO}}_{2}$$ injection and production laterals could help maximize $${\mathrm{CO}}_{2}$$ storage and hydrocarbon recovery in depleted reservoirs and in down-dip residual oil zones.

Description: 〈span〉〈div〉ABSTRACT〈/div〉Different from most tight oil reservoirs, the tuffaceous tight oil of the Tiaohu Formation is not in situ oil, and no close contact exists between the source rock and reservoir in the Malang sag (Santanghu Basin, China). This study determined the mechanism of hydrocarbon accumulation of this tuffaceous tight oil reservoir through an integrated analysis of oil–source rock correlation, reservoir characteristics, and rock wettability combined with a comprehensive analysis of geological conditions. An oil–source rock correlation using biomarkers and stable carbon isotopes shows that the crude oil originated from underlying source rocks in the Lucaogou Formation. The oil in the tuffaceous tight reservoir is not indigenous but has migrated over a long distance to accumulate in these reservoirs. Faults and fractures that developed at the end of the Cretaceous are the oil migration pathways. Vitric and crystal-vitric tuffs constitute the main rock types of the tuffaceous tight reservoir. Matrix-related pores in the tuffs mainly comprise interparticle pores between minerals and dissolution intraparticle pores formed by devitrification. The adsorption of polar components of the oil generated from original organic matter in the tuff leads to wettability of lipophilicity, which is the main reason for hydrocarbon charging and accumulation. To our knowledge, this is the first comprehensive study reporting this finding.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Predicting vertical and lateral facies variations in various depositional environments remains a major challenge in the oil and gas industry because it impacts petroleum system assessments and the associated exploration-risking phase. The use of multidisciplinary constraints (geomorphology, geology, geophysics) in forward stratigraphic models sheds light on the complex interaction of local, regional, and global driving mechanisms that influence sediment transport and deposition along continuously evolving landscapes. In this paper, we develop an integrated statistical approach to examine the sensitivity of forward stratigraphic models in complex salt provinces to several parameters, including water discharge, sedimentary load, grain size and associated diffusion coefficients, and slope. This statistical analysis was applied to the Barremian–Albian sequence of the central Scotian Basin (Canada) and highlights the influence of complex salt kinematics on sediment pathway diversion and accumulation around salt domes and canopies. Forward stratigraphic modeling results point to regions of higher probability of Lower Cretaceous sandy reservoirs. Automating simulation runs significantly reduced the time required to achieve a statistically valid number of simulations and allowed the sensitivity of the model to be evaluated.〈/span〉

Description: 〈span〉In his comment on our paper about the hyperpycnites in the Triassic Yanchang Formation, G. Shanmugam puts forward that hyperpycnites do not exist. Consequently, he considers our interpretation that hyperpycnal flows are an important depositional process in the Yanchang Formation to be invalid. We unravel his arguments and demonstrate that evidence supports our assertion that hyperpycnal flows were an important sedimentary process in the lake in which the Yanchang Formation accumulated. Moreover, we provide proof from modern observations that hyperpycnal flows do exist in lakes.〈/span〉