ALBERT

Description: The Arctic changes rapidly in response to global warming and is expected to change even faster in the future (IPCC 2001, 2007, 2013). Large areas of the shelves and continental slopes bordering the Arctic Ocean are characterized by permafrost and the presence of gas hydrates. Future global warming and potential hydrate dissociation in the Arctic Ocean challenge the slope stability of these areas. This may lead to slope failures. The first, and so far only reported, large-scale slope failure in the Arctic Ocean is the Hinlopen/Yermak Megaslide (HYM), which is located in front of the Hinlopen glacial trough north of Svalbard. During cruise MSM31 onboard the German R/V MARIA S. MERIAN we investigated this giant slope failure and the deeper structure of the Sophia Basin in detail to elucidate the potential causes of the main and following failure events as well as to test existing hypotheses on the generation of this giant submarine landslide. We studied the megaslide and the adjacent so far not failed shelf areas by means of multibeam swath bathymetry, Parasound sediment echo sounder, low- and high-resolution multichannel seismic reflection profiling. The seismic data image bottom-simulating reflectors beneath not failed areas of the slope, as well as a buried gas escape pipe. On the shelf, shallower than the gas hydrate stability zone, we observed widespread gas seepage as flares in the Parasound echo sounder data. These flares rise from a seafloor highly disturbed by iceberg scouring. Therefore, we could not identify pockmarks in the multibeam data. At one location, we sampled a flare by means of a CTD probe close to the seafloor and proofed that the emanating gas has a high methane concentration. The new data indicate that the existence of gas and gas hydrates beneath the shelf north of Svalbard was one key factor causing slope instability in the past and may also cause further slope failures in the future.

Description: The modern polar cryosphere reflects an extreme climate state with profound temperature gradients towards high-latitudes. It developed in association with stepwise Cenozoic cooling, beginning with ephemeral glaciations and the appearance of sea ice in the late middle Eocene. The polar ocean gateways played a pivotal role in changing the polar and global climate, along with declining greenhouse gas levels. The opening of the Drake Passage finalized the oceanographic isolation of Antarctica, some 40 Ma ago. The Arctic Ocean was an isolated basin until the early Miocene when rifting and subsequent sea-floor spreading started between Greenland and Svalbard, initiating the opening of the Fram Strait / Arctic-Atlantic Gateway (AAG). Although this gateway is known to be important in Earth’s past and modern climate, little is known about its Cenozoic development. However, the opening history and AAG’s consecutive widening and deepening must have had a strong impact on circulation and water mass exchange between the Arctic Ocean and the North Atlantic. To study the AAG’s complete history, ocean drilling at two primary sites and one alternate site located between 73°N and 78°N in the Boreas Basin and along the East Greenland continental margin are proposed. These sites will provide unprecedented sedimentary records that will unveil (1) the history of shallow-water exchange between the Arctic Ocean and the North Atlantic, and (2) the development of the AAG to a deep-water connection and its influence on the global climate system. The specific overarching goals of our proposal are to study: (1) the influence of distinct tectonic events in the development of the AAG and the formation of deep water passage on the North Atlantic and Arctic paleoceanography, and (2) the role of the AAG in the climate transition from the Paleogene greenhouse to the Neogene icehouse for the long-term (~50 Ma) climate history of the northern North Atlantic. Getting a continuous record of the Cenozoic sedimentary succession that recorded the evolution of the Arctic-North Atlantic horizontal and vertical motions, and land and water connections will also help better understanding the post-breakup evolution of the NE Atlantic conjugate margins and associated sedimentary basins.

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: Modeling of fluid flow in naturally fractured reservoirs is often done through modeling and upscaling of discrete fracture networks (DFNs). The two-dimensional fracture geometry required for DFNs is obtained from subsurface and outcropping analog data. However, these data provide little information on subsurface fracture aperture, which is essential for quantifying porosity and permeability. Apertures are difficult to obtain from either outcropping or subsurface data and are therefore often based on fracture size or scaling relationships, but these do not consider the orientation and spatial distribution of fractures with respect to the in situ stress field. Using finite-element simulations, mechanical aperture can be modeled explicitly, but because changes in fracture geometry require renewed meshing and simulating, this approach is not easily integrated into subsurface DFN modeling workflows. We present a geometrically based method for calculating the shear-induced hydraulic aperture, that is, an aperture of up to 0.5 mm (0.02 in.) that can result from shear displacement along irregular fracture walls. The geometrically based method does not require numerical simulations, but it can instead be directly applied to DFNs using the fracture orientation and spacing distributions in combination with an estimate of the regional stress tensor and orientation. The frequency distribution of hydraulic aperture from the geometrically based method is compared with finite-element models constructed from five real fracture networks, digitized from outcropping pavements. These networks cover a wide range of possible geometries and spatial distributions. The geometrically based method predicts the average hydraulic aperture and equivalent permeability of fractured porous media with error margins of less than 5%.

Description: Numerical geochemical modeling was used to study the effects on pore-water composition and mineralogy from carbon dioxide (CO 2 ) injection into the Pennsylvanian Morrow B Sandstone in the Farnsworth Unit in northern Texas to evaluate its potential for long-term CO 2 sequestration. Speciation modeling showed the present Morrow B formation water to be supersaturated with respect to an assemblage of zeolite, clay, carbonate, mica, and aluminum hydroxide minerals and quartz. The principal accessory minerals in the Morrow B, feldspars and chlorite, were predicted to dissolve. A reaction-path model in which CO 2 was progressively added up to its solubility limit into the Morrow B formation water showed a decrease in pH from its initial value of 7 to approximately 4.1 to 4.2, accompanied by the precipitation of small amounts of quartz, diaspore, and witherite. As the resultant CO 2 -charged fluid reacted with more of the Morrow B mineral matrix, the model predicted a rise in pH, reaching a maximum of 5.1 to 5.2 at a water–rock ratio of 10:1. At a higher water–rock ratio of 100:1, the pH rose to only 4.6 to 4.7. Diaspore, quartz, and nontronite precipitated consistently regardless of the water–rock ratio, but the carbonate minerals siderite, witherite, dolomite, and calcite precipitated at higher pH values only. As a result, CO 2 sequestration by mineral trapping was predicted to be important only at low water–rock ratios, accounting for a maximum of 2% of the added CO 2 at the lowest water–rock ratio investigated of 10:1, which corresponds to a small porosity increase of approximately 0.14% to 0.15%.

Description: Substrate relief is a common characteristic of hard-bottom offshore banks and is associated with benthic biodiversity. Earlier studies revealed varying relief associated with offshore mesophotic communities. Correlations may exist between relief and benthic biodiversity, which in turn may be useful in determining drill sites. Such drill site determination requires obtaining an estimate of variability in relief on these banks and its associated geographic patterns. We performed fine-scale surveys of relief on 14 banks in the Gulf of Mexico to examine variation between them, geographic patterns, and possible processes influencing them: 28 Fathom, 29 Fathom, Alderdice, Bouma, Bright, Elvers, Geyer, Horseshoe, McGrail, Parker, Rankin, Rezak, Sidner, and Sonnier Banks. We used a multibeam sensor on a remotely operated vehicle, with resolution of approximately 0.5 m (2 ft). Average and standard deviation of relief were calculated at the transect, drop site, and bank levels of resolution. Sidner and McGrail Banks had the highest relief, and 29 Fathom and Sonnier had the lowest. Sidner Bank had relief averaging up to 11 m (36 ft) in height, whereas 29 Fathom Bank exhibited the lowest relief (range 1 to 2 m [3 to 7 ft]). Bright Bank and all others exhibited intermediate and variable relief at both the transect and drop site levels. Relief is not predictable on many banks because of high variability between drop sites. Some low-relief banks are predictable in their relief, lending themselves to predictions of benthic diversity and suitable drill sites. Relief decreased significantly as one moved northward in the study region. Relief exhibited a significant sinusoidal pattern from west to east. Banks with low relief occurred off Lake Calcasieu and Lafayette, Louisiana.

Description: The Lower Cretaceous presalt section in the Kwanza Basin contains an excellent petroleum system that includes "synrift" strata (Barremian) overlain by a "sag" interval (Aptian) and capped by the Loeme Salt. The upper synrift is generally limestone with widespread mollusk packstones and grainstones (coquinas) deposited in a fresh-to–moderately saline (alkaline) lake. The sag interval is characterized by carbonate platforms and silica-rich isolated buildups formed in highly evaporated, highly alkaline lakes. Shrubby (dendritic), microbially influenced boundstones and intraclast–spherulite grainstones accumulated in shallow water on platform tops. Microbial cherts were deposited as organic buildups on large, isolated structural highs basinward (west) of platforms, and they apparently formed at low temperatures in very alkaline lake water. Shrubby boundstones and microbial cherts have vuggy pores that are primary and result in high permeability. Wackestones and packstones with calcitic grains (mainly spherulites) in dolomite or argillaceous dolomite were deposited in slightly deeper, low-energy sag environments. In addition, clays (especially stevensite) precipitated out of the silica-rich, highly alkaline lake waters. During sag deposition, calcite precipitated on the shallow lake floor with morphologies that ranged from spherulites to shrubs and included a continuum of intermediate forms. Spherulites probably precipitated just below the sediment–water interface. Spherulites and shrubby calcites are commonly recrystallized. Spherulites floating in stevensite probably formed in deeper lacustrine environments. Organic-rich mudstones were deposited in even deeper lacustrine environments in synrift and sag intervals, and they are likely the source of most hydrocarbons in this system. These interpretations are supported by seismic, core, petrographic, and stable isotope data.

Description: The natural fracture system developed in the Cardium sandstone is examined in four outcropping structures that represent different stages of fold development. At the incipient stage of folding, the fracture system is dominated by large, widely spaced hybrid fractures that have very small displacements and are aligned in the regional shortening direction (type I orientation). These fractures are naturally propped open by asperities along the fracture surfaces. A lesser number of small thrust faults (type III orientation) are also developed. Extension fractures aligned parallel to the fold axis (type II orientation) begin to develop in the early stage of folding. Through the intermediate stage of folding, there is a progressive increase in the intensity of both type I and type II orientation fractures. Incremental increases in shear displacement on new or reactivated fractures create a gouge of comminuted sandstone grains along the fracture interface. As folding progresses to an advanced stage, there is major increase in the amount of shear displacement on both type I and type II orientation fractures. Many existing fractures coalesce into connected fracture zones and small faults that have shear offsets ranging from several centimeters to several meters. A breccia can result from intense fracturing in the rock within and marginal to these shear features. Slickensides on type I orientation features consistently indicate slip in a subhorizontal direction, even as bed dip increases. Multiple slickenside patterns record reactivation of these features. Type II orientation fractures and small faults consistently undergo bed-perpendicular slip. Type I and type II features both serve to stretch the Cardium sandstone beds but in different directions. Only type III features, which are a minor component of the fracture population, result in bed thickening.

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: CONFLICT OF INTEREST AND OTHER RELEVANT INFORMATION: Conflict of interest information is provided below for the authors of this paper. Chesapeake Energy Corporation (Chesapeake) funded the authors of this paper through their organizations of employment and, in the case of the senior author, privately, to do basic research to evaluate this very large data set and prepare the paper. Data were collected on behalf of Chesapeake by paid third-party consultants to comply with regulatory programs. The analyses and interpretations, and report writing, were done by the authors of the paper. The decision to submit the paper was that of the authors. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake. During the preparation of this paper, all authors worked for the organizations noted in authorship. Mark Hollingsworth is a current employee of Chesapeake, having worked there from February 2011 to the present. Prior to Mr. Hollingsworth’s employment by Chesapeake, he worked for TestAmerica Laboratories, Inc., which provided laboratory analytical consulting services to Chesapeake. Bert Smith is a former employee of Chesapeake, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal from November 2013 to the present. Enviro Clean Cardinal also does consulting work for Chesapeake. Prior to May 2013, Mr. Smith worked for Science Applications International Corporation, which did consulting work for Chesapeake. Elizabeth Perry works for AECOM, who provides energy consulting services to government and private industry, including Chesapeake. Rikka Bothun also worked for AECOM during most of the time this paper was under preparation but left AECOM in December 2014 and now works for a private consulting company that does not do consulting work for Chesapeake. None of the following authors (Don Siegel, Bert Smith, Elizabeth Perry, or Rikka Bothun) have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences Journal. Mark Hollingsworth is a current employee of Chesapeake and owns stock in the company in an amount in excess of $5000. Donald Siegel is the lead author and contributor to the manuscript’s preparation, technical interpretations, and review of these data and the manuscript. Bert Smith contributed to the manuscript preparation, technical interpretations, and review of these data and the manuscript. Elizabeth Perry and Rikka Bothun contributed to the manuscript preparation, technical interpretations, and review. Mark Hollingsworth maintains the Chesapeake baseline data set and contributed to the manuscript preparation and review of these data and the manuscript. Due to confidentiality agreements with landowners whose wells were sampled, latitude and longitude cannot be shown on maps.

Description: CONFLICT OF INTEREST AND OTHER RELEVANT INFORMATION: Chesapeake Energy Corporation funded consultants and the authors of this paper through their organizations of employment and, in the case of Donald Siegel, privately to do basic research on this temporal data set and prepare the paper. The authors of this report did all analysis and writing. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake Energy Corporation. During the preparation of this paper, all authors worked for the organizations noted in authorship. Bert Smith is a former employee of Chesapeake Energy Corporation, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal since November 2013. While employed at Chesapeake Energy Corporation, he managed this temporal study, which was completed shortly after he left Chesapeake Energy Corporation. Enviro Clean Cardinal also does consulting work for Chesapeake Energy Corporation. Prior to May 2012, Bert Smith worked for Science Applications International Corporation, which consulted for Chesapeake Energy Corporation. Mark Becker has worked for Chesapeake Energy Corporation since March 2012; prior to that, he worked for the US Geological Survey for 24 yr. Donald Siegel works for Syracuse University, but he was funded privately for this work. Neither Bert Smith nor Donald Siegel have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences . Mark Becker is a current employee of Chesapeake Energy Corporation and owns stock in the company in an amount in excess of $5000. Bert Smith is the lead author and contributed to the paper preparation, technical interpretations, and review of these data and paper. Mark Becker contributed to the paper preparation, technical interpretations, and review of these data and paper. Donald Siegel contributed to the paper preparation, technical interpretations, and review of these data and paper.

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〉Hyperspectral systems that image drill core can capture detail mineralogical information at the millimeter scale and thus have the potential to enable investigators to characterize shale composition and heterogeneity, complementing the direct chemical and x-ray diffraction analysis of core samples and guiding detailed sampling. This method provides insight into petrophysical and geomechanical properties because these properties are significantly correlated to rock composition. We tested this approach on a continuous long core from the shale sequence of the Horn River Group in the Horn River Basin, British Columbia, sampled at a spacing of 1 m (40 in.) and analyzed for geochemical composition. These data enable the calibration of spectral imagery to rock composition and specifically predict total organic carbon (TOC) and the abundance of SiO〈sub〉2〈/sub〉, Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉, K〈sub〉2〈/sub〉O, and CaO. We then imaged nine samples from the Woodford Shale from the Permian Basin, Texas, for a blind test to assess the predictive models. The models were then used to predict TOC and geochemical data over detailed imagery of 300 m (984 ft) of Horn River Group shale core and portray their spatial variability downhole as images and profiles. In its simplest form, hyperspectral imagery can be enhanced to highlight fabric in shale core that otherwise is difficult to visualize because of low brightness. In addition, we show that spectral imagery of shale can also be processed to either convey mineralogical (quartz, clay, and carbonate) or geochemical information. The resulting views can readily be used to guide the selection of samples and may provide tools for scaling reservoir properties from individual plugs to reservoir volumes.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Considerable attention has been directed to the Devonian Horn River Formation in western Canada with respect to geochemical evaluation of gas-generation and storage potential. Because organic geochemical analyses are not always useful for characterizing the type and amount of original organic matter, we surmise the original kerogen type and original hydrogen index (HIo) and subsequently estimate a reliable original total organic carbon (TOCo) based on a combination of inorganic and organic geochemical data. Productivity (SiO〈sub〉2〈/sub〉 and Ba) and terrestrial input (Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉, Hf, Nb, and Zr) proxies are used to estimate original kerogen types, which suggest that the Evie and Muskwa Members formed under conditions of high productivity and minor terrestrial input. These members also formed under reducing conditions, as indicated by the redox proxies (Mo, U, and Th/U). Under such conditions, primarily type II kerogen was preserved.By considering the fraction of biogenic silica, the estimated HIo values (400–500 mg hydrocarbon/g total organic carbon [TOC]) for the middle Otter Park Member are lower than that for Evie and Muskwa Members and higher than the upper and lower Otter Park Member. The stronger correlation between TOCo and trace elements suggests that HIo is useful for reconstructing the coherent variation in TOCo. Based on the original kerogen type and TOCo, the gas-generation and storage potentials of the Evie, middle Otter Park, and Muskwa Members are higher than those of other members. The source-rock potential is excellent for the Evie Member with an approximately 75% difference between TOCo and measured present-day TOC.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The global Precambrian–Cambrian system includes an important series of hydrocarbon-bearing strata. However, because rocks of this age are typically deeply buried, few petroleum exploration breakthroughs have been made, and the presence of source rocks remains somewhat controversial. Recently, commercial condensate and gas were discovered from the deep (∼6900 m [∼22,600 ft]) Zhongshen 1C (ZS1C) exploratory well drilled in the Tazhong uplift of the Tarim Basin, China, leading to renewed interest in the development of Cambrian source rocks in the basin. On the basis of outcrop reconnaissance and sample testing from around the Tarim Basin, we show that a set of high-quality source rocks were developed within the lower Cambrian Yuertusi Formation (Є〈sub〉1〈/sub〉y), at the base of the lower Cambrian. These rocks are black shales and typically have a total organic carbon content between 2% and 6% but extending as high as 17% in selected regions. This marine sequence is 10–15 m (33–49 ft) thick in some outcrops along the margins of the basin. Seismic data indicate that these high-quality source rocks may cover an area as large as 260,000 km〈sup〉2〈/sup〉 (100,000 mi〈sup〉2〈/sup〉). Their main organic parent material was benthic multicellular algae. On the basis of high-temperature thermal simulations conducted on these source rocks, we show that the gas composition and carbon isotopes from the ZS1C well are similar to the products generated at a thermal evolution stage corresponding to a vitrinite reflectance of between 2.2% and 2.5%. Late-stage natural gas accumulated within these rocks over time. The δ〈sup〉34〈/sup〉S correlation of organic sulfur compounds in the condensate with Cambrian sulfates provides further evidence for a Є〈sub〉1〈/sub〉y source rock origin of the ZS1C condensate and gas. The Cambrian dolomites in association with a salt seal exhibit favorable geological conditions for large-scale hydrocarbon accumulation. A new set of deep exploration strata can, therefore, be developed, guiding future deep Cambrian hydrocarbon exploration in the Tarim Basin.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The effects of reservoir heterogeneity on the development of submarine channel fields are still poorly understood because of lack of direct evidence for fluid flow. This study uses integrated well logs and three-dimensional seismic data from the Niger Delta Basin to characterize the previously undocumented spatial distribution of shale units and permeability contrasts within a submarine channel system. Combining these data with four-dimensional (4-D) seismic data facilitates the exploration of the controls of reservoir heterogeneity on fluid flow during development. The results show that the studied submarine channel system consists of multiple vertically stacked channel complex sets (CCSs) from CCS1 (oldest) to CCS5 (youngest), which are separated from each other by continuous shale barriers. The CCS2–CCS4, which are located in the stratigraphic middle of the channel system, are the main development layers because of their higher permeabilities and lower permeability contrasts. The 4-D seismic responses validate that the presence of shale barriers between vertically adjacent CCSs can hinder the flow of fluids between CCSs. Fluid flow between vertically adjacent CCSs barely occurs except in localized erosional locations where the sand fills of different CCSs are vertically connected. Each CCS consists of multiple individual channels, which can be separated by inclined shale baffles if they laterally migrate in one direction. As the 4-D seismic responses demonstrate, such inclined shale baffles can hinder fluid flow between adjacent individual channels and help to form multiple narrow flow paths in map view. The absence of inclined shale baffles also produces prominent permeability contrasts within each CCS, which are characterized by relatively high–permeability zones that are parallel to the channel axis. Comparison of this permeability distribution and the 4-D seismic responses shows that injected water preferentially sweeps along relatively high–permeability zones, which can help to form single wide flow paths with higher sweep efficiency or single narrow flow paths with lower sweep efficiency.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Source-to-sink analyses show that northern Gulf of Mexico (GOM) Wilcox Group siliciclastic deep-water systems are linked to transport of sediments from the Laramide tectonic belt into the deep basin. Less is known, however, about southern GOM sedimentation. New drilling and discoveries in the Mexican deep water have generated considerable interest since the opening of Mexico to international exploration. To investigate Paleogene deposition in Mexico’s offshore areas, a three-phased approach was employed: (1) seismic mapping of deep-water depocenters, (2) regional stratigraphic analysis of potential basin entry points, and (3) prediction of submarine-fan dimensions using empirical scaling relationships. Isochore and structural mapping of the Wilcox depocenters used available well and seismic data. Potential basin entry points were identified by evaluation of Wilcox fluvial–deltaic systems and tectonic elements. Empirical scaling relationships previously established between fluvial and deep-water segments provide first-order predictions of submarine-fan dimensions.Paleogene Wilcox source-to-sink systems of the greater GOM basin change north to south as a function of varied tectonics and sedimentary accommodation. The United States sector was a passive margin: continental-scale drainage systems fed a broad, gently dipping shelf. By contrast, the southern GOM basin was a tectonically active margin: smaller-scale fluvial systems sourced from the Hidalgoan uplands flowed directly into foreland basins located on the slope. Results presented here indicate that several systems rimming the southern GOM were able to effectively transfer sediment from the mountain belt into the basin. Regional observations and semiquantitative predictions of fan dimensions provide a context for future detailed work based on new well and seismic information.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Sequence stratigraphy based on wire-line logs, cores, and outcrops is entering its fourth decade of mainstream usage in industry and academia. The technique has proved to be an invaluable tool for improving stratigraphic analyses in both clastic and carbonate settings. Here we present a simple quantitative technique to support sequence stratigraphic interpretations in clastic shallow marine systems. The technique uses two pieces of data that are readily available from every subsurface field or outcrop study: (1) parasequence thickness (T) and (2) parasequence sandstone fraction (SF). The key assumptions are that parasequence thickness can be used as a proxy for accommodation at the time of deposition and parasequence sandstone fraction can be used as a proxy for sediment supply. This means that quantitative proxies for rates of accommodation development and sediment supply can be acquired from wire-line logs, cores, and outcrop data. Vertical trends in parasequence thickness divided by sandstone fraction (T/SF) approximate trends expected in systems tracts for changes in ratios of rate of accommodation development to rate of sediment supply. The technique, termed “TSF analysis,” can also be applied at lower-order sequence and composite sequence scales. It provides a quantitative and objective methodology for determining rank and order of sequence stratigraphic surfaces and units. Absolute T/SF values can be used to determine shoreline, stacked shoreline, and shelf-margin trajectories. Four case studies are presented, which demonstrate the robustness of the technique across a range of different data sets. Implications and potential future applications of TSF analyses are discussed.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Eagle Ford Formation has attracted considerable industry attention as a self-sourced unconventional shale reservoir. The productive interval in the Eagle Ford Formation is the transgressive systems tract, which contains parasequences whose lithologic content varies upward with increasing proportions of limestones. Optimum success in both exploration and production depends on the adequate characterization of fracture systems as a function of lithology. The outcrops present along US Highway 90 in Val Verde and Terrell Counties, Texas, provide considerable insight into the regional natural fracture system of the Eagle Ford Formation. Fracture-orientation analysis reveals two sets of conjugate hybrid shear fractures and two sets of regional fractures. Abutting relationships suggest that hybrid shear fractures formed first, followed by the thoroughgoing northeast-striking fracture set, and finally by a northwest-striking set, which tends to be confined to individual mechanical units. The orientation of these fractures suggests that they formed during post-Laramide stress relaxation and progressive exhumation. Spacing-frequency distribution analysis of the fracture population reveals a mature hypersaturated fracture system that likely formed at depth by overburden load and/or fluid pressure near maximum burial. Our results indicate that the Eagle Ford Formation displays a well-developed fracture network regionally distributed in the Val Verde Basin, and likely present in the productive Eagle Ford play. These observations provide evidence for pathways and vertical connectivity for potential fluid pathways throughout the Eagle Ford Formation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉We document a novel approach to balanced three-dimensional structural restoration based on an adaptation of the GeoChron model. Conventionally, the GeoChron model defines a transformation of a geological model to a flattened space (U-V-T), with paleogeographic coordinates defined by the horizontal axes (U-V) and geologic time on the vertical axis (T). In our new balanced structural restoration scheme, the complete stratigraphy is restored using a transformation constrained only by the datum horizon. Scaling the vertical “T” axis to depth in a manner that preserves volume or layer thickness results in a geometric restoration that approximately minimizes strain globally. This restoration provides a geometrically plausible representation of the geologic structure at the time when the datum horizon was deposited. Restoration is independent of mechanical rock properties and is thus most applicable to regions in which mechanical rock properties are approximately homogeneous. Restoration kinematics may be constrained by growth strata if present.We validate the method with kinematic forward models and a laboratory sandbox model and apply it to two natural examples to demonstrate its capabilities for model validation and palinspastic restoration.We identify four criteria for assessing the validity of a structural model using the results of restoration: (1) anomalous fault throw, (2) timing of fault activity, (3) fault compliance, and (4) restoration strain. Analysis of the sandbox results and limitations of volume conservation derived from uncertainties in compaction states suggest accuracy of the method to be in the 5%–20% range.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The pore structure of shale has a significant effect on hydrocarbon migration and the long-term gas supply of shale gas wells. The present study investigates the spontaneous imbibition characteristics to evaluate the pore connectivity and wettability of marine Longmaxi shale samples from the southeastern Chongqing area and continental Yanchang shale samples from the Ordos Basin. The pore-size distribution obtained from N〈sub〉2〈/sub〉 adsorption and mercury intrusion porosimetry, field emission–scanning electron microscopy, and focused ion beam–scanning electron microscopy photos are used to interpret the imbibition behaviors. Our results show that the difference in dominant pore type between marine and continental samples, which is dominated by thermal maturity, controls on their imbibition behaviors as well as their wettability. Organic matter (OM) pores within Yanchang samples are poorly developed because of their low thermal maturity, and a large amount of water-wet inorganic pores are preserved in these samples because of relatively weak compaction. Oil-wet OM pores are well developed in Longmaxi samples with higher thermal maturity, and inorganic pores have been largely eliminated because of strong compaction. The low pore connectivity to water for both the Longmaxi and Yanchang samples is indicated by the low water imbibition slopes. Furthermore, the more oil-wet property of the Longmaxi samples and more water-wet characteristics of the Yanchang samples are obtained by comparing the directional water/oil imbibition slopes. In addition, the positive meaning of quartz in the protection of pore spaces is found in both the Longmaxi and the Yanchang samples used in this study.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Multiple natural gas fields have been discovered in the Baiyun depression and the adjoining Panyu lower uplift in the Pearl River Mouth Basin, northern South China Sea. The natural gases are associated with condensate and are characterized by relatively heavy carbon isotopes, with methane and ethane δ〈sup〉13〈/sup〉C values ranging from –44.2‰ to –33.6‰ and –30.0‰ to –25.4‰, respectively. Nearly all methane and ethane are derived from oil-prone type II kerogen in the Wenchang Formation source rock, whereas the heavy hydrocarbon gases (propane, butanes, and pentanes) are derived from both the Wenchang and Enping (type III kerogen) Formations, based on an integrated comparison of carbon isotopic compositions of the natural gases, typical type I/II and type III kerogen-derived gases, and the Enping and Wenchang kerogens. The gases from the eastern parts of the Baiyun depression and the Panyu lower uplift mainly originate from secondary oil cracking and primary kerogen cracking, respectively. The gases from the northern slope of the Baiyun depression are a mixture of oil-cracking and kerogen-cracking gases. Both oil-cracking and kerogen-cracking gases were mainly generated from the Wenchang Formation source rock in the maturity range of 1.5%–2.5% vitrinite reflectance, with a corresponding present-day depth range of 5400–6500 m (17,700–21,300 ft). The apparent contribution of the Wenchang Formation to the discovered gas accumulations demonstrates that it is the most important source rock in the area, instead of the Enping Formation. The search for more gas derived from oil cracking will be the next natural gas exploration direction in the Baiyun depression.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The northern Appalachian Basin depocenter of Pennsylvania represents one of the most economically important hydrocarbon-producing areas in the United States, yet the thermal conditions that promoted hydrocarbon formation within the basin are only marginally constrained. The prolific coal, oil, and natural gas fields of Pennsylvania are the direct result of thermal maturation of once deeply buried organic-rich sediment. Understanding how, why, and where thermal maturation occurred in the Appalachian Basin requires high-quality heat flow and thermal conductivity measurements, as well as paleotemperature estimates and basin modeling. To improve the understanding of heat flow, we present, to our knowledge, the first direct measurements of (1) thermal conductivity on Devonian core samples and (2) equilibrium temperature versus depth logs for the northern Appalachian Basin depocenter. Results from three well sites demonstrate that heat flow is conductive and nearly uniform, averaging 34 ± 2.5 mW/m〈sup〉2〈/sup〉, with an average thermal gradient of 29 ± 4°C/km. The new heat-flow measurements are significantly lower (30%–50% less) than previously published estimates that used nonequilibrium bottomhole temperature values and empirically derived thermal conductivity estimates. Our analysis indicates that previous studies correctly estimated the regional thermal gradient using bottomhole temperatures but overestimated heat flow in this region by as much as 50% because of inaccurate extrapolation of thermal conductivity. The results highlight the importance of directly measuring thermal conductivity to accurately quantify heat flow in deep sedimentary basins. Ultimately, additional paleotemperature data are necessary to improve our understanding of Appalachian Basin thermal evolution.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Shale samples of the Marcellus Shale from a well drilled in northeastern Pennsylvania were used to study diagenetic effects on the mineral and organic matter and their impact on petrophysical response. We analyzed an interval of high gamma ray and anomalously low electrical resistivity from a high thermal maturity (mean maximum vitrinite reflectance 〉 4%) part of the shale‐gas play. A suite of microanalytical techniques was used to study features of the shale down to the nanoscale and assess the level of thermal alteration of the mineral and organic phases.The samples are organic rich, with total organic carbon contents of 3–7 wt. %; the vast majority of the organic matter was identified as highly porous pyrobitumen. Matrix porosity is also present, especially within the clay aggregates and at the interface between rigid clasts and clay minerals.Mineral- and organic-based thermal maturity indices suggest that during burial the sediment had been exposed to temperatures as high as 285°C (545°F). Under these conditions, the residual, migrated organic matter assumed a partially crystalline habit as confirmed by the identification of turbostratic structures via electron microscopy imaging. Experimental dielectric measurements on organic matter–rich samples confirm that the anomalous electrical properties observed in the wire-line logs can be ascribed to the presence of an electrically conductive interconnected network of partially graphitized organic matter. The preservation of porosity suggests that this organic network can contribute not only to the electrical properties but also to the gas flow properties within the Marcellus Shale.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Understanding natural fracture networks in the subsurface is highly challenging, as direct one-dimensional borehole data are unable to reflect their spatial complexity, and three-dimensional seismic data are limited in spatial resolution to resolve individual meter-scale fractures.Here, we present a prototype workflow for automated fracture detection along horizontal scan lines using terrestrial light detection and ranging (t-LIDAR). Data are derived from a kilometer-scale Pennsylvanian (locally upper Carboniferous) reservoir outcrop analog in the Lower Saxony Basin, northwestern Germany. The workflow allows the t-LIDAR data to be integrated into conventional reservoir-modeling software for characterizing natural fracture networks with regard to orientation and spatial distribution. The analysis outlines the lateral reorientation of fractures from a west–southwest/east–northeast strike, near a normal fault with approximately 600 m (∼1970 ft) displacement, toward an east–west strike away from the fault. Fracture corridors, 10–20 m (33–66 ft) wide, are present in unfaulted rocks with an average fracture density of 3.4–3.9 m〈sup〉−1〈/sup〉 (11.2–12.8 ft〈sup〉−1〈/sup〉). A reservoir-scale digital outcrop model was constructed as a basis for data integration. The fracture detection and analysis serve as input for a stochastically modeled discrete fracture network, demonstrating the transferability of the derived data into standard hydrocarbon exploration-and-production-industry approaches.The presented t-LIDAR workflow provides a powerful tool for quantitative spatial analysis of outcrop analogs, in terms of natural fracture network characterization, and enriches classical outcrop investigation techniques. This study may contribute to a better application of outcrop analog data to naturally fractured reservoirs in the subsurface, reducing uncertainties in the characterization of this reservoir type at depth.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Using cores, well logs, and other borehole data, the results of this study show that the shallow-water lacustrine delta has its own unique depositional characteristics of the third member of Oligocene Dongying Formation (Ed〈sub〉3〈/sub〉) in the Baxian sag, Bohai Bay Basin, eastern China. During the Ed〈sub〉3〈/sub〉 stage, the rift–thermal basin subsidence transition stage, the paleoslope was divided into multilevel slopes by faults along the Wen’an slope with slope angles from approximately 0.19° to 2.02°. The paleogeographic conditions, low-discharge channel, and low accommodation controlled the sedimentary characteristics. The distributions of the shallow-water delta system were controlled by multilevel flexure slopes. The delta plain was distributed on the first- and second-level slope belts, and the delta front was distributed on the third-level slope belt. The high-sinuosity fluvial channel of the delta plain was the dominant facies in the whole shallow-water delta. Most sand was deposited in these channels along the second-level slope belt. Therefore, not enough sand was present to be transported into the lake (shallow water) to form mouth bars in the delta front. Therefore, mouth bars of the shallow-water delta front were few, and the sand beds were thin. Additionally, no more sand was available to be supplied right along to deep lake, the lacustrine basin was small, and there was insufficient accommodation and sand to develop a subaqueous fan in the delta front.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Three-dimensional reservoir modeling is an important aspect to determine the heterogeneity of organic-rich shale reservoirs, an area of study that continues to be explored and refined. A large proportion of data acquired from horizontal wells causes issues in the structural and property modeling for shale reservoirs. Since horizontal wells are designed to drill into a specific, narrow zone, their horizontal section tends to parallel or nearly parallel formation surfaces. As a result, formation surfaces have a much more complex spatial location relationship with horizontal wellbores than with vertical wellbores. The existing algorithms are not good at addressing this issue during structural modeling. The major problem of using horizontal well data in property modeling is the biased data set because their horizontal section tends to stay within a narrow zone. The property distribution feature estimated from this biased data set, as a significant, default input of geostatistical simulation algorithms, causes the constructed property models to deviate away from the real case in the subsurface. A method to infer more formation tops in pseudovertical wells according to a series of assumptions was developed to provide more constraint points for structural modeling within the areas of the horizontal well section. To use the biased database from horizontal wells, distribution function and trend model methods were developed for continuous property modeling, and percentage and probability trend models were developed for discrete property modeling. The Longmaxi–Wufeng shale in the Fuling gas field of Sichuan Basin was used as an example to express and verify these methods.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉An integrated approach to detect new areas of potential interest associated with stratigraphic traps in mature basins is presented. The study was carried out in the Middle Magdalena Valley basin, Colombia. The workflow integrates outcrop and subsurface interpretations of facies, activity of faults, and distribution of depocenters and paleocurrents and makes use of them to construct a three-dimensional exploration-scale geocellular facies model of the basin. The outcrop and well log sedimentological analysis distinguished facies associations of alluvial fan, overbank, floodplain, and channel fill, the last one constituting the reservoir rock. The seismic analysis showed that tectonic activity was coeval with the deposition of the productive units in the basin and that the activity ended earlier (before the middle Miocene) along the western margin than along the eastern margin. Paleogeographic reconstructions depict transverse and longitudinal fluvial systems, alluvial fans adjacent to the active basin margins, and floodplain facies dominating the structural highs and the southwestern depositional limit. These reconstructions provided statistical data (lateral variograms) to construct the model. The exploration-scale facies model depicts the complete structure of the basin in three dimensions and the gross distribution of the reservoir and seal rocks. The predictive capability of the model was evaluated positively, and the model was employed to detect zones of high channel fill facies probability that form bodies that are isolated or that terminate upward in pinchouts or are truncated by a fault. Our approach can prove helpful in improving general exploration workflows in similar settings.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Knowledge of in situ stress distribution is fundamental for coalbed methane production; however, it is poorly understood in the eastern Yunnan region, South China. In this study, the horizontal maximum (〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉) and minimum (〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉) principal stress and vertical stress (〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉) were systematically analyzed for the first time. The results indicated that the magnitudes of 〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉, 〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉, and 〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉 showed positive correlations with burial depth. In general, three types of in situ stress fields were determined: (1) 〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉 〉 〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉 〉 〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉 in shallow layers with burial depths less than approximately 600 m (∼1970 ft) below ground level (bgl), indicating a dominant strike-slip faulting stress regime; (2) in medium layers approximately 600–800 m (∼1970–2625 ft) bgl, the in situ stress state followed multiple relationships, suggesting that the in situ stress regime was transformed; and (3) 〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉 〉 〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉 〉〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉 in deep layers with burial depths greater than approximately 800 m (∼2625 ft) bgl, indicating a dominant normal faulting stress regime. Coal permeabilities obtained from injection–falloff well tests showed that they were widely distributed, and no obvious relationships were found between coal permeability and effective in situ stress magnitude. In the study area, the development and orientation of previously generated natural fractures combined with the present-day in situ stress distribution controlled the permeability in coal reservoirs. Differential stress and presence of natural fractures significantly affected the geometry and pattern of hydraulic fractures. In addition, in the eastern Yunnan region, locations with relatively deep depths in vertical wells and approximately west–northwest/east–southeast-trending horizontal wells suffered high potential of borehole instability because of the high differential stress.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In carbonate rock reservoirs, spatial distribution models and elastic properties are complex because of diagenetic processes and mineralogical composition, which together directly interfere with variations in pore shape and interconnectivity. The main objective of this paper is to propose a workflow to aid in three-dimensional quantitative carbonate reservoir characterization of the Quissamã Formation (Macaé Group) in the Pampo field of the Campos Basin, offshore Brazil. Model-based seismic inversion, sequential Gaussian simulation with cokriging for porosity modeling, and truncated Gaussian simulation with trend for facies modeling were used to characterize the carbonate reservoirs. Our results show that the carbonate platform is located between the upper Aptian and lower Albian seismic surfaces. Interpretation of a new surface, called the intra-Albian, was possible via acoustic-impedance (AI) analysis. Our workflow facilitated identification of low AI, high porosity, and best facies areas in structural highs where the most productive wells have been drilled. Facies modeling suggests that intercalation of facies with high and low porosities is connected to shallowing-upward cycles. Finally, several debris facies with low AI and high porosities were identified in an area that could be targeted for new exploration.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thick marine shales occur in the Wufeng Formation and Longmaxi Formation of Sanquan Town of the Nanchuan District, Chongqing Municipality, which is located on the southeast margin of the Sichuan Basin. However, few details of the characteristics of the Wufeng–Longmaxi shales in this area have been reported. In this study, a well approximately 100 m (∼328 ft) deep was drilled. A high-quality shale (total organic carbon [TOC] 〉2.0 wt. %, clay 〈40%) interval that was approximately 24 m (∼79 ft) thick with an average TOC value of 3.0 wt. % mainly occurs in the Ordovician Wufeng Formation (Katian and Hirnantian) and base of the Silurian Longmaxi Formation (Rhuddanian). Shales with higher TOC values commonly have a higher porosity and specific surface area. Tectonic movements may also have been very important factors that influenced the petrophysical properties of the shales. For example, a detachment layer that resulted from complex tectonic movements is extensive in the Wufeng Formation. The cracks and microcracks in the detachment layer can result in good pore connectivity. Consequently, the detachment layer can be an effective migration pathway. The Longmaxi–Wufeng shales of Sanquan Town are also compared with those of the famous Jiaoye 1 well in the Jiaoshiba shale gas field in the eastern Sichuan Basin. Although the shales in Sanquan Town have considerable shale gas generation potential, the shale gas resource potential in Sanquan Town is probably poor because the escape of shale gas may be accelerated by the detachment layer in destroyed anticlines and synclines.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The ability to accurately predict the probability of fluid migration from depth through existing wells based on known well properties, such as age and depth, would be enormously helpful in understanding how migration pathways develop and the identification of potential migration without extensive field tests. The presence of fluid pathways is an important environmental issue because such pathways allow gas, either naturally occurring methane or sequestered CO〈sub〉2〈/sub〉, to move into the atmosphere. In this paper, we explore the ability of various predictive models to forecast gas migration at existing wells in Alberta, Canada, based upon the characteristics of existing deep wells. Alberta was selected as a case study because of the availability of data in an area that has required wells to be tested for pathway development after rig release since 1995. Wells that do not demonstrate pathway development require no further testing until the well is abandoned. We show that accurately predicting fluid migration requires detailed information on well construction, production, and fluid properties, and even then, the models considered in this study misclassify a large number of wells. This suggests other factors may contribute to pathway formation. Of the models investigated, random forests provide the best results on this data set, correctly identifying 78% of the wells used.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This study aims to decipher the groundwater status of the parts of Tigray area, Ethiopia using an integrated methodology of remote sensing and geographic information systems (GIS). Digitized vector maps of the study area, that is, geology, land use and/or cover, and drainage, were generated and converted to raster data. The theme weight and class weights were assigned to the raster maps of the respective parameters. Weight age to the layers was assigned using an analytical hierarchy process and further overlay analysis was carried out in the ArcGIS environment to decipher the groundwater resources of the study area.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The present contribution aims for a characterization of microstructure and pore-space distribution of upper Visean Rudov beds, considered the main source rock for conventional oil deposits in the Ukrainian Dneiper–Donets Basin and a prospect for unconventional hydrocarbon production in recent years. Broad ion beam–scanning electron microscopy (SEM) mapping revealed a remarkably heterogeneous microstructure controlled by diagenetic precipitates (Fe/Mg carbonates, albite). Formation of these precipitates is likely triggered by organic matter decomposition and represents an important influencing factor for overall porosity and permeability. Furthermore, shale diagenesis also influences mechanical properties, as suggested by nanoindentation tests. The SEM-visible organic matter porosity is restricted to solid bitumen; although pores less than 2–3 nm in vitrinites of overmature samples are indicated by focused ion beam–SEM results, they cannot be resolved clearly by this method. Pore generation in solid bitumen that likely formed in situ in primary amorphous organic matter already starts at the early oil window in samples from the basinal oil-prone organofacies, whereas most porous solid bitumen at peak oil maturity was interpreted as relicts of primary oil migration, representing an earlier oil phase that predominantly accumulated in quartz-rich layers and became nanoporous during secondary cracking. In the terrestrially dominated transitional to marginal organofacies, pore generation in pyrobitumen resulting from gas generation occurs significantly later and is less intense. Formation of authigenic clay and carbonate minerals within pyrobitumen is likely related to organic acids formed during bitumen decomposition and implies the presence of an aqueous phase even in pores that are apparently filled exclusively with solid bitumen.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Ahdeb oil field is located in the Mesopotamian Basin of central Iraq within a northwest–southeast-trending anticline. Seven oil-bearing layers exist in the eastern area in the field, but there is only one oil-bearing layer in the western area. This study reveals that the reservoir filling process resulted from the difference in the elements in the petroleum system, the oil generation and migration process, and the formation of the structural trap. Most oils in the field, with pristane/phytane 〈 1 and a high relative abundance of hopanes exceeding C〈sub〉30〈/sub〉, were generated from the Upper Jurassic–Lower Cretaceous Chia Gara Formation, whereas some oils were generated from the Lower Cretaceous Ratawi and Zubair Formations. The mid-Upper Cretaceous reservoirs in the field are composed of lime grainstones, packstones, and wackestones.The main oil accumulation occurred during the Maastrichtian, coinciding with peak oil generation from the Chia Gara Formation with a 50% transformation ratio from organic matter to oil. The reservoirs of the eastern structural trap in the field were filled with large amounts of medium to heavy oils. After the formation of two structural traps in the western area in the mid-Miocene, oils pre-existing in the second layer of the Khasib Formation in the east began migrating toward the structural traps in the west during the late Miocene, as verified by relatively higher 1-/4-methylcarbazole and 1,8-/2,7-dimethycarbazole ratios of oils in the west than that in the east and residual solid bitumen in the east. The strike-slip fault might also have restricted oil or gas migration during the Miocene, limiting oil accumulation in the west.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The success of hydraulic fracturing and increasing use of basin-modeling packages drive the need to understand the effects of hydrocarbon (HC) generation on the mechanical properties of source rocks. A better understanding of relationships among geological, geochemical, and geomechanical parameters can potentially reduce the uncertainties associated with conventional and unconventional prospect evaluation.We present a simulation of microcrack growth based on a three-dimensional source-rock system. Upon thermal maturation, the kerogen transforms into lighter products, most of which are HCs. The generated products exert excessive pore pressure to the system resulting from the effect of volume expansion; this pressure is released through the expansion of pore space and formation of microcracks. Using linear elasticity and linear elastic fracture mechanics, our model calculates microcrack sizes (surface areas, lengths, apertures, and volumes) and the amount of overpressure throughout the maturation process. We validated this model with experimental data from 〈a href="https://pubs.geoscienceworld.org/aapgbull#b20"〉Kobchenko et al. (2011)〈/a〉, and performed sensitivity analysis for both laboratory and geological settings. Much larger microcracks are generated in laboratory settings compared to the subsurface because of the lack of overburden, resulting in secondary porosity over 100 times larger than the original organic porosity and crack lengths obtaining millimeter scale. In contrast, microcracks are much smaller in geological settings because of the presence of significant overburden and stiffer rock frames: the crack apertures are in the submicron regime with a crack length ranging from 100 to 300 μm. The formation of microcracks connects isolated microscale HC pockets, providing pathways for primary migration.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Studies of lacustrine carbonate rocks in continental rifts have received huge interest in recent years because of their great economic value in the South Atlantic. However, most existing facies and tectonosedimentary models for carbonate platforms are based on marine carbonate systems, whereas models for nonmarine systems are scarce. The main aim of this paper is to establish such models and to further our understanding of the hydrocarbon-bearing late synrift Lower Cretaceous carbonate successions of the Campos Basin, Brazil. This paper is based on a proximal to distal industrial data set of three-dimensional (3-D) seismic, cores, and well logs from the Coqueiros Formation (Coquina), southern Campos Basin. The dominant carbonate facies in the Coqueiros Formation are mollusk-rich grainstones, rudstones, and floatstones, which form the main reservoir facies. The 3-D seismic interpretations show an oblique extensional rift system, characterized by a series of grabens, half grabens, accommodation zones, and horsts oriented northeast–southwest to north–northeast-south–southwest. Three tectonic domains are recognized based on structural style, stretching factors, and subsidence rates as well as facies and different types of lacustrine carbonate platforms. Proximal rift margin areas are characterized by a series of half grabens with footwall and hanging-wall dip slopes of shallow lacustrine carbonates and fluviodeltaic mixed carbonate and siliciclastic deposits in marginal, hanging-wall basins. Central areas are carbonate rich with platforms established over horst blocks surrounded by deeper-water carbonate facies. Distal areas have the highest amount of stretching and subsidence and accumulate the thickest carbonate successions over a template of buried horsts and grabens. The entire carbonate succession underlies a thick layer of Aptian salt, which forms the seal to this prolific hydrocarbon system.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The uppermost Middle Triassic Leikoupo Formation in the western Sichuan Basin of China has recently been shown to host as much as 5.3 tcf (1.5 × 10〈sup〉12〈/sup〉 m〈sup〉3〈/sup〉) of natural gas resources. The reservoir rocks, composed mainly of microbially derived dolomudstone (e.g., thrombolites and stromatolites), are characterized by low porosity (〈8%) and permeability (〈0.001 to 10 md). The limestone is commonly tight and not of reservoir quality because of abundant meteoric calcite cementation, whereas the dolostone has various types of pores dominated by solution-enlarged pores and vugs, microbial framework pores, and micropores. Breccias are well developed in places, probably because of dissolution of underlying evaporites (e.g., anhydrite) by an influx of low-salinity fluids (e.g., freshwater and seawater) during an early burial stage. Early dolomitization created micropores in the dolomudstone, and subsequent diagenetic events were dominated by calcite, dolomite, quartz cementation, pyrite replacement, compaction, fracturing, and development of stylolites. Localized hydrothermal activity has been evidenced by high homogenization temperatures (∼160°C–200°C) obtained from fluid inclusions in fracture-filling cements. Bacterial sulfate reduction probably resulted in H〈sub〉2〈/sub〉S generation, pyrite precipitation, and solution-enlarged pore and vug formation, whereas part of the current H〈sub〉2〈/sub〉S in these reservoirs may have been sourced from thermochemical sulfate reduction or an underlying formation (e.g., the Feixiangguan Formation). Development of microfractures and associated micropores was probably the final diagenetic event, which improved pore interconnectivity. This study confirms the effect of diagenesis on the development of a microbial dolomudstone reservoir, which may be applicable to other similar microbial carbonate reservoirs elsewhere, for example, Middle Triassic sections of the Tethys region and offshore Brazil.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Clinoforms, the basic large-scale architectural form within which sediments are stored and eventually fed down depositional dip in clastic wedges, exist in many shapes and sizes. Understanding how they form, evolve, and degrade is critical to understanding how transport mechanisms affect the shelf margin and sediment partitioning and distribution, and their implications on the presence of a working petroleum system. The Neogene stratigraphic succession of the Taranaki Basin in New Zealand contains clinoform packages that display a variety of architectures well imaged on seismic data. Quantitative characterization of this interval was performed to unravel the processes by which clinoforms evolve under the influence of tectonic- and isostatic-driven subsidence, sea-level change, and sediment supply fluctuations. Nine different clinoform packages were identified on the basis of changes in their seismic stratigraphic characteristics. Two-dimensional stratigraphic forward modeling was used to conduct a sensitivity analysis and determine the relative importance of different geologic controls on their genesis. Our results show that during the early to late Pliocene, clinoform architectures were influenced by the opening of a back-arc rifting structure in the Taranaki Basin (northern graben), which controlled sediment redistribution and partitioning. At the same time, a drop in global sea level allowed sediment bypass to distal parts of the basin. During the late Pliocene, changes in the Australian–Pacific subduction zone forced rapid uplifting of the Southern Alps, generating a significant increase in sediment supply. Model simulations suggest that clinoform architectures during the late Pliocene were controlled by this increase in sediment supply and associated loading.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A detailed, rock-based investigation of three Upper Cretaceous Eagle Ford Group cores situated behind, at, and downdip of the Lower Cretaceous Stuart City paleoreef-shelf margin in south Texas was conducted to understand stratigraphic, sedimentological, and geochemical relationships across this buried shelf margin. An understanding of how the Eagle Ford Group lithofacies vary across the paleoreef-shelf margin is currently lacking. We therefore examined a dip section of three cores across the antecedent shelf margin and delineated seven Eagle Ford lithofacies: (1) massive argillaceous mudstone, (2) massive to laminated foraminiferal lime wackestone, (3) radiolarian and foraminiferal dolomitic to lime packstone, (4) massive to bioturbated skeletal lime wackestone, (5) laminated foraminiferal lime packstone, (6) laminated inoceramid and foraminiferal lime grainstone, and (7) massive to bioturbated claystone. A basinward decrease in calcite from 60% to 48% is accompanied by an increase in clay minerals from 12% to 20%. The low-relief raised rim of the older, buried Stuart City paleoshelf margin may have acted as a barrier, dividing the Eagle Ford Group into two sedimentological systems: (1) a restricted drowned shelf to the north, and (2) an open-marine basinal setting to the south. The lower to upper Cenomanian Eagle Ford strata on the drowned shelf are cyclic and enriched in molybdenum, suggesting anoxic to euxinic water masses. The anoxic, open-marine, basinward strata are less cyclical and have a lower molybdenum (compared with the drowned shelf) content. Ash beds and gravity-flow deposits are rare south of the margin. A depositional model was constructed of the lower and upper Eagle Ford formations.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Predicting the lateral distribution of petroleum play elements (reservoirs, source rocks, and seals) requires basic understanding of regional basin evolution and depositional history. In remote areas where little data are available or where the basins have undergone episodes of tectonic deformation, this understanding relies on integrated analysis of the plate tectonic framework and the resulting paleogeography. The Arctic has experienced several episodes of tectonic deformation, which fundamentally changed the basin configuration and patterns of sediment routing. Here, we present a set of paleogeographic maps highlighting these changes during the Triassic–Paleogene. In the Triassic, the Arctic was characterized by a central restricted basin, which predominantly received clastic input from the Polar Urals and Arctic Canada. The Alaskan and Siberian passive margins received clastics from continent-scale drainage systems extending into the North American craton and the central Asian fold belt, respectively. In the Jurassic, the region was dominated by rifting as the central Arctic landmass rifted away from Laurentia. In the Early Cretaceous, the northern margin of the Barents Sea underwent regional uplift resulting in new provenance areas shedding sediments southward. Compression along the Pacific margin formed continuous topography and high sediment input to the Canada Basin during the Late Cretaceous. Regression in the Canada Basin continued in the Paleogene when major rift–tip deltas formed. This overview of Arctic paleogeography demonstrates the complexity of this overall data-poor area and shows the need for integrated, regional models to understand sediment routing and stratigraphic development in such areas.〈/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: As the largest active strike-slip fault zone of east Asia, the Tan-Lu fault zone is the most significant tectonic feature controlling the hydrocarbon accumulation in Bohai Bay. The Penglai 19-3 and Penglai 25-6 fields are the most typical examples among the fields found in the Tan-Lu fault zone. The structures related to the two fields are fault restraining bends produced by dextral strike-slip movement on faults within the Tan-Lu fault zone. The structures initiated at the late depositional stage of the third member of the Eocene Shahejie Formation (ca. 40 Ma) after the deposition of the main source rocks of the basin. They then experienced a main development stage during deposition of the second and first members of the Eocene Shahejie Formation and the Oligocene Dongying Formation (40–25 Ma). During the Neogene, the structures continued to be enhanced slightly because of continued strike-slip until the early to middle Pleistocene. These structures were characterized by the absence of the preponderance of the reverse separations on faults and might represent the restraining bends in a divergent wrench deformation zone. This study shows that restraining bend structures along intrabasinal strike-slip systems formed after the deposition of the source rocks are very favorable for hydrocarbon accumulation.

Description: The distribution of porosity was examined on seven drill cores from west–central Alberta encompassing the Belle Fourche and Second White Specks Formations. These Cenomanian–Turonian mudrocks from the Western Canada Sedimentary Basin exhibit good organic richness (〉2 wt. % total organic carbon) and marine kerogen type II with limited kerogen type III. With the increasing thermal maturity from approximately 0.43% vitrinite reflectance ( R o ) to approximately 0.90% R o , the total porosity decreases from approximately 9 to approximately 1 vol. %. This change translates to a reduction in total pore volume from approximately 0.05 to approximately 0.005 cm 3 /g and is accompanied by changes in relative proportions of micropore, mesopore, and macropore volumes. Variations in total porosity for the seven cores with different thermal maturities across Alberta are mainly related to mesoporosity and macroporosity, although the in-core variations in total porosity are mainly related to microporosity. In general, organic matter micropores contribute to the overall microporosity in the seven cores across the study area. The increase in the total pore volumes is in accordance with an increasing concentration of quartz, although increasing concentrations of chlorite and kaolinite may contribute to greater abundance of micropores in the seven cores. The in-core variations suggest that greater contents of kaolinite and illite may contribute to increasing mesopore volumes. Variations in pore volumes and pore size distribution with depth within individual cores (representing specific thermal maturity level) differ from what is observed laterally, when cores of various thermal maturity levels across Alberta are compared, indicating complex controls on porosity systems.

Description: The stratigraphic organization of early synrift clastic successions is controlled by the rates of tectonic subsidence and the growth of the master faults, which, coupled with eustatic base level change, control the generation of accommodation. The 100- to 300-m (328- to 984.2-ft)-thick, highly heterolithic Lower Jurassic upper Åre and Tilje succession (Halten terrace, offshore Norway) represents an example of ancient synrift deposits that accumulated within a north–northeast-south–southwest-oriented structurally controlled embayment where sedimentation was strongly influenced by tidal currents but with significant river influence and minor wave action, except in exposed distal locations. The shallowing-upward, deltaic Tilje succession was deposited near the lowstand shoreline. The Tilje Formation consists of two tabular second-order sequences, each of which overlies structurally influenced sequence boundaries (SB2 and SB3 in local terminology) associated with rift-related tectonic pulses. The first pulse led to formation of SB2 (shallow incision into the Åre Formation) and caused a regional geomorphological change of the basin from an open, wave-dominated setting (upper Åre Formation) to a funnel-shaped, tide-dominated setting (Tilje Formation), in which the lower sequence 2 accumulated. Sequence 3 rests erosively on sequence 2 and is characterized by proximal tidal deposits showing at least two main oblique to axial fluvial input points (north–northwest and northeast), with an increase in wave influence and deepening toward the south. Local rapid subsidence of elongated, narrow hanging wall basins exerted a subtle control on the succession thickness and distribution of tidal–fluvial distributary channels. The overall tabular geometry and internal architecture of the Tilje Formation is less complex than that of other tidal successions worldwide, showing lateral and vertical compartmentalization of the best tidal–fluvial sandstone reservoirs.

Description: Carbonate reservoir rocks exhibit a great variability in texture that directly impacts petrophysical parameters. Many exhibit bi- and multimodal pore networks, with pores ranging from less than 1 μm to several millimeters in diameter. Furthermore, many pore systems are too large to be captured by routine core analysis, and well logs average total porosity over different volumes. Consequently, prediction of carbonate properties from seismic data and log interpretation is still a challenge. In particular, amplitude versus offset classification systems developed for clastic rocks, which are dominated by connected, intergranular, unimodal pore networks, are not applicable to carbonate rocks. Pore geometrical parameters derived from digital image analysis (DIA) of thin sections were recently used to improve the coefficient of determination of velocity and permeability versus porosity. Although this substantially improved the coefficient of determination, no spatial information of the pore space was considered, because DIA parameters were obtained from two-dimensional analyses. Here, we propose a methodology to link local and global pore-space parameters, obtained from three-dimensional (3-D) images, to experimental physical properties of carbonate rocks to improve P-wave velocity and permeability predictions. Results show that applying a combination of porosity, microporosity, and 3-D geometrical parameters to P-wave velocity significantly improves the adjusted coefficient of determination from 0.490 to 0.962. A substantial improvement is also observed in permeability prediction (from 0.668 to 0.948). Both results can be interpreted to reflect a pore geometrical control and pore size control on P-wave velocity and permeability.

Description: With the booming exploration and development of unconventional hydrocarbon resources in source rocks, the estimation of total organic carbon (TOC) content from well logs has become increasingly important because of the significance of TOC in the formation evaluation of those resources. In this paper, a new log overlay method is developed to estimate the TOC content of source rocks with excess radioactivity, but containing little or no potassium feldspar. Specifically, on the basis of previous results of log responses of source rocks, it is believed that the natural gamma ray (GR) log responses of source rocks in the applicable conditions are predominantly contributed by clay minerals and organic matter. A practical clay indicator is established to reflect the clay content using density and neutron logs. The indicator is effective not only in nonsource rocks that contain oil or water but also in source rocks. Furthermore, a new method was developed by overlaying the properly scaled clay indicator curve on the GR curve. In nonsource rocks, including clay-rich rocks and reservoirs saturated with oil or water, the two curves overlie each other, whereas a separation between the curves occurs in organic-rich source rocks. The separation between the curves was defined and expressed and can be used to calculate the TOC consecutively after careful calibration with core data. This method has been successfully applied to two shale gas plays with high-maturity kerogen in the Sichuan Basin, China. In addition, a source rock with low-maturity kerogen was used to verify the new method for its effectiveness, reliability, and widespread adaptability.

Description: Geochemical fingerprinting of produced water from hydraulic fracturing projects is an essential tool to trace their provenance during the postfracturing period, to quantify recovery rates and volumes of fracturing fluids, and to visualize the geodynamic structure of natural or induced fracture networks. A total of 41 produced water samples from an exploration well in the Northern Arabia Exploration Area in Saudi Arabia were collected daily from the fracture-stimulated Qusaiba hot shale and analyzed for major ions and trace elements and partially for environmental isotopes. The postfracturing period shows an initial return of supply water and potassium chloride brine, subsequently replaced by the inflow of sodium chloride–type formation water with a stable plateau salinity of 50,000 mg/L. Less than 10% of the total injected fracturing fluids were recovered during postfracturing, whereas 78.8 vol. % of the total recovered fluid is composed of formation water (20,843 out of 26,446 bbls) during the study period. Coinciding values between logged reservoir temperature and calculated geothermometers confirm the provenance of pore water from the Qusaiba hot shale or from nearby units. The recharge of the Silurian sequence with meteoric surface water occurred during the early Holocene (6–6.7 ka), as evidenced by geochronological dating with the 14 C method and 18 O/ 2 H values close to the global meteoric water line. The inflow of formation water into the stimulated shale layer in the postfracturing stage could be originated by the natural occurrence of pore water within a naturally fractured, black shale layer or, more likely, by the rise of groundwater from the underlying Sarah sandstones via migration pathways of natural or newly formed, vertically induced hydraulic fractures. For this particular well site and the specific hydraulic fracturing project, chemical and isotopic fingerprinting confirms the absence of ascending migration pathways from the Silurian Qusaiba hot shale toward a shallower groundwater system, which are isolated through a lithological set of more than 900 m (3000 ft) of impermeable mudstone from the Qusaiba Member.

Description: Oxygen isotope ( 18 O) zonation in carbonate mineral cements is often employed as a proxy record (typically with millimeter-scale resolution) of changing temperature regimes during different stages of sediment diagenesis. Recent advances in secondary ion mass spectrometry allow for highly precise and accurate determinations of cement 18 O values to be made in situ on a micrometer scale, thus significantly increasing the spatial resolution available to studies of diagenesis in sandstone–shale and carbonate systems. Chemo-isotopically zoned dolomite–ankerite cements within shaly sandstone beds of the predominantly silty–shaly Eau Claire Formation (Cambrian, Illinois Basin) were investigated, revealing the following: with increasing depth of burial (from 〈0.5 to ~2 km [〈1500 to 6500 ft]), cement 18 O values decrease from a high of approximately 24 down to approximately 14 (on the Vienna standard mean ocean water [VSMOW] scale, equivalent to –6.5 to –16.5 on the Vienna Peedee belemnite [VPDB] scale). The observed cross-basin trend is largely consistent with cements having formed in response to progressive sediment burial and heating. Within the context of independent burial and thermal history models for the Illinois Basin, cementation began soon after deposition and continued intermittently into the mid-Permian. However, temperatures in excess of burial model predictions are inferred at the time of latest ankerite cement precipitation, which we propose overlapped in time with conductive heating of the Eau Claire Formation (a closed system) from under- and overlying sandstone aquifers that channeled the flow of hot, Mississippi Valley–type mineralizing brines during the mid-Permian (ca. 270 Ma).

Description: The Bohai Sea area, offshore of the Bohai Bay Basin, is one of the most petroliferous regions in China, with proven original oil in place of approximately 2.4 x 10 9 m 3 (150.94 x 10 8 bbl) and proven original gas in place of over 5 x 10 12 m 3 (1.76 x 10 13 ft 3 ). Cumulative oil production is over 50 million tons (3.5 x 10 8 bbl). In this study, using the limited data on source rock thickness, core samples, and Rock-Eval pyrolysis along with sedimentary facies analysis, source rock characteristics of different depositional settings were identified, and the thickness, richness, organic matter type, and thermal evolution of four sets of source rocks in the Bohai Sea area— the second member of Dongying Formation (E 3 d 2 ), the third member of Dongying Formation (E 3 d 3 ), the first and second members of Shahejie Formation (E 2 s 1-2 ), and the third member of Shahejie Formation (E 2 s 3 )—were predicted and evaluated. Subsequently, the intensity and history of hydrocarbon expulsion for different sags was systematically compared and analyzed. The greatest thickness of the four sets of source rocks in the Bohai Sea area is 400–800 m (1300–2600 ft). The average richness of the organic matter of these source rocks is 1.74%–2.87%. The E 2 s 3 set has the highest organic matter abundance; E 2 s 1-2 has the lowest. The organic matter of these source rocks is mainly type I and type II, but their evolutions differ. The vitrinite reflectance of E 3 d 2 is 0.5%–1.0%, that of E 3 d 3 is 0.7%–1.25%, that of E 2 s 1-2 is 0.75%–1.75%, and that of E 2 s 3 is 0.75%–2.0%. The cumulative hydrocarbon expulsion of the four sets of rocks is 4.14 x 10 10 t (2.90 x 10 11 bbl). The E 2 s 1-2 set has the greatest expulsion amount: 1.75 x 10 10 t (1.22 x 10 11 bbl). The peak stages of hydrocarbon expulsion of the four sets of source rocks were during Neogene Minghuazhen Formation (12.2–2.0 Ma) and Neogene Guantao Formation (16.6–12.0 Ma). The Bozhong sag expelled the most hydrocarbons, followed by the Liaozhong, Qikou, and Huanghekou sags.

Description: Schlumberger’s modular dynamics tester (MDT) tool was used to test 10 Miocene sands in the Tubular Bells deep water oil field, offshore Gulf of Mexico, United States. Nine sands from true vertical depths of 19,999–26,464 ft (6096–8066 m) were sampled from a single well and another deeper sand (29,075 ft [8,862 m]) from a second well. Using ion and strontium, oxygen, and hydrogen isotopic analysis, the nine MDT water samples were demonstrated to be mostly formation water. The sample in the second well from 29,075 ft (8862 m) is filtrate, based on its oxygen and hydrogen isotopic composition (–4.10 and –26.3, standard mean ocean water [SMOW]). Insufficient water was recovered for ionic analysis, which made the isotopic analysis even more important to help document the origin of the water in what appears to be a hydrocarbon-charged interval. Using a combination of chemical and isotopic analyses, it is concluded that only two of the sands are possibly in fluid communication or separated by baffles. The other sands are each in separate fluid compartments. The salinity (total dissolved solids) of the formation waters decreases with depth and distance from the salt and ranges from approximately 39,000 to more than 288,000 mg/L. The formation waters have oxygen and hydrogen isotopic compositions ranging from +3.19 to +4.52 and –16.1 to –19.4, respectively (SMOW). Bromide–chloride systematics indicate that the formation waters are mixtures of normal seawater and seawater that was evaporated to and probably beyond halite saturation. The evaporite water is sourced from the deeper Jurassic section (Louann Salt) and likely came up along the salt–sediment interface along faults and fractures associated with emplacement of the salt stock and canopy. The formation waters were subsequently enriched in chloride and sodium to varying degrees by dissolution of the diapiric salt. Strontium isotopes are compatible with mixing of highly concentrated (evaporative) Jurassic seawater with relatively low 87 Sr/ 86 Sr ratios and much less concentrated (almost seawater salinity) pore water with more radiogenic strontium, the latter derived from silicate reactions during burial diagenesis. Short-chain organic acids are present in high concentrations (〉1000 mg/L) along with the organophilic ions boron and iodide. The concentrations of boron, iodide, and organic acids do not correlate with salinity. Boron and iodide show a strong positive relationship with each other and a less strong, but positive, relationship with organic acid concentrations. Boron and iodide are nearly twice as concentrated in waters of oil-bearing sands than in water-bearing sands and appear to be indicators of hydrocarbon proximity. One water-bearing sand has concentrations of boron and iodide as high as those seen in oil-bearing sands, possibly suggesting an updip oil accumulation.