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  • American Association of Petroleum Geologists (AAPG)
  • 1
    Journal cover
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    American Association of Petroleum Geologists (AAPG) | GeoScienceWorld
    Online: 1.1917 – (GFZ only)
    Print: 34(12).1950 – 93(4).2009 (Location: A17, Kompaktmagazin, 9/7 - 10/6)
    Formerly as: The American Association of Petroleum Geologists Bulletin; Bulletin of the American Association of Petroleum Geologists; Bulletin of the Southwestern Association of Petroleum Geologists  (1917–1980)
    Publisher: American Association of Petroleum Geologists (AAPG) , GeoScienceWorld
    Print ISSN: 0016-7606 , 0149-1423
    Electronic ISSN: 1943-2674
    Topics: Geosciences
    Keywords: GeoScienceWorld ; petrology ; Erdöl ; Erdölgeologie ; Erdölgewinnung ; Erdgas ; Erdgasgeologie
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  • 2
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    American Association of Petroleum Geologists (AAPG) | GeoScienceWorld | formerly Blackwell Publishing
    Online: 4.1997 – (GFZ only)
    Publisher: American Association of Petroleum Geologists (AAPG) , GeoScienceWorld , formerly Blackwell Publishing
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
    Topics: Geography , Geosciences
    Keywords: GeoScienceWorld
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  • 3
    Publication Date: 2015-08-04
    Print ISSN: 0149-1423
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  • 4
    Publication Date: 2015-08-04
    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.
    Print ISSN: 0149-1423
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  • 5
    Publication Date: 2015-08-04
    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).
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  • 6
    Publication Date: 2015-08-04
    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.
    Print ISSN: 0149-1423
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  • 7
    Publication Date: 2015-08-04
    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.
    Print ISSN: 0149-1423
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  • 8
    Publication Date: 2015-08-04
    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.
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  • 9
    Publication Date: 2015-08-04
    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.
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  • 10
    Publication Date: 2015-08-04
    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.
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  • 11
    Publication Date: 2015-08-04
    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.
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  • 12
    Publication Date: 2015-09-25
    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.
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
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  • 13
    Publication Date: 2015-06-02
    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.
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  • 14
    Publication Date: 2015-06-02
    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.
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  • 15
    Publication Date: 2015-06-02
    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.
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  • 16
    Publication Date: 2015-06-02
    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.
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  • 17
    Publication Date: 2015-06-02
    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.
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  • 18
    Publication Date: 2016-07-16
    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%.
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  • 19
    Publication Date: 2016-07-21
    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%.
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  • 20
    Publication Date: 2016-07-21
    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.
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  • 21
    Publication Date: 2016-07-16
    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.
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  • 22
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2016-07-16
    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.
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  • 23
    Publication Date: 2013-09-14
    Description: We describe the structure, microstructure, and petrophysical properties of fault rocks from two normal fault zones formed in low-porosity turbiditic arkosic sandstones, in deep diagenesis conditions similar to those of deeply buried reservoirs. These fault rocks are characterized by a foliated fabric and quartz-calcite sealed veins, which formation resulted from the combination of the (1) pressure solution of quartz, (2) intense fracturing sealed by quartz and calcite cements, and (3) neoformation of synkinematic white micas derived from the alteration of feldspars and chlorite. Fluid inclusion microthermometry in quartz and calcite cements demonstrates fault activity at temperatures of 195°C to 268°C. Permeability measurements on plugs oriented parallel with the principal axes of the finite strain ellipsoid show that the Y axis (parallel with the foliation and veins) is the direction of highest permeability in the foliated sandstone (10 •2 md for Y against 10 •3 md for X, Z, and the protolith, measured at a confining pressure of 20 bars). Microstructural observations document the localization of the preferential fluid path between the phyllosilicate particles forming the foliation. Hence, the direction of highest permeability in these fault rocks would be parallel with the fault and subhorizontal, that is, perpendicular to the slickenlines representing the local slip direction on the fault surface. We suggest that a similar relationship between kinematic markers and fault rock permeability anisotropy may be found in other fault zone types (reverse or strike-slip) affecting feldspar-rich lithologies in deep diagenesis conditions.
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  • 24
    Publication Date: 2013-09-14
    Description: This work discusses concepts related to the occurrence of salt along weakness planes, such as faults and fractures, which resemble igneous intrusions and may result in peculiar seismic features. We suggest that mechanisms for the formation of these structures basically involve the creation of extensional faults (commonly associated with crestal collapse grabens), which are rotated and migrated to structural flanks by domation, creating interesting seismic features here referred to as halokinetic rotating faults. At the time of their formation, some of these faults may be incipiently intruded by salt as a way of relieving sporadic intense internal overpressure episodes in the salt body, by regional compression, and/or by buoyancy effects compensating the density difference between salt and surrounding sediments. The relatively low overburden pressure at the crest of the diapir and the original high dip angles of these fault planes favor salt intrusions near the diapir apex. The process may occur in several cycles along the salt dome evolution, creating several generations of salt apophyses positioned in the diapir apex and flanks, resulting in different dips and areas of extension. These intrusions sometimes resemble the branches of Christmas tree structures, which are commonly formed by extrusive mechanisms. Although well and seismic data point to the occurrence of salt along fault planes, we recognize that salt is not a low-viscosity fluid, and the mechanisms to allow its penetration along fault planes remain unknown. Some of the possible mechanisms, which are commonly associated with a later phase of regional compression, are discussed in this work. The implications for petroleum exploration may have been overlooked in the recent exploration campaigns in the deep-water regions of the Brazilian margin. Halokinetic rotating faults, when partially filled with salt, are sometimes responsible for common pitfalls observed in seismic and well data interpretation. When fault planes present subhorizontal dips and high reflectivity, caused by the presence of salt, they have been mistakenly interpreted as flatspots, a well-known seismic hydrocarbon indicator. When drilled and proved to correspond to thin evaporite intervals in well data, these salt apophyses have also been misinterpreted as younger localized evaporitic events overlying the main salt body.
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  • 25
    Publication Date: 2013-09-20
    Description: The Cretaceous rocks of Florida have been recognized as potentially suitable reservoirs for geologic carbon dioxide (CO 2 ) sequestration. Specifically, the upper member of the Upper Cretaceous Lawson Formation, together with the lower part of the Paleocene Cedar Keys Formation, is presented here as a potential composite CO 2 storage reservoir that is mainly composed of porous dolostone sealed by thick anhydrites of the overlying middle Cedar Keys Formation. Many of the porous intervals within the Cedar Keys-Lawson storage reservoir display lateral continuity and have an average porosity range of 20%–30%. The estimated CO 2 storage capacity for the reservoir is approximately 97 billion t of CO 2 , which means the Lawson and Cedar Keys Formations composite reservoir could potentially support CO 2 sequestration for hundreds of large-scale power plants in the southeastern United States for their entire 40-yr lifespan. Because most of the previous research on the Lawson Formation is concentrated in north-central and northeastern Florida and southern Georgia, this study further characterizes the formation and its CO 2 sequestration potential in south-central and southern Florida.
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
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  • 26
    Publication Date: 2013-09-20
    Description: Geochemical reactions that may occur on CO 2 injection into a sandstone formation in Missouri (MO) were investigated by means of geochemical modeling. Five possible injection sites were considered: two in the northwestern part of the state, two in the northeastearn part, and one in the southwestern part. The Geochemist Workbench software was used to investigate solubility trapping and mineral precipitation. Modeling was performed for two periods: an injection period of 10 yr and a postinjection period where the reactions proceeded to equilibrium. The work presented substantial challenges. Among them are uncertainty in kinetic constants for the dissolution and precipitation of minerals on CO 2 injection. Model results include equilibrium values for CO 2 stored via solubility trapping ranging from 49-g CO 2 /kg free formation water in Northeast MO to 78-g CO 2 /kg free formation water for Southwest MO. Mineral trapping is significantly lower, between 2.6- and 18.4-g CO 2 /kg free formation water. The model shows siderite and dawsonite as the major carbonate minerals formed, in this order. On a volumetric basis, northwest MO sequestration values were slightly greater than those obtained for northeast MO because of the somewhat greater depth and higher injection pressure at the injection target (Lamotte Sandstone) at the northwestern sites. However, the greater thickness of the aquifer for the northeastern sites provided overall greater sequestration capacity. Greene County was altogether unfit for sequestration because of the low total dissolved solids value of the formation water.
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  • 27
    facet.materialart.
    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2013-10-04
    Description: We present a new hypothesis for the Jurassic plate-tectonic evolution of the Gulf of Mexico basin and discuss how this evolution influenced Jurassic salt tectonics. Four interpretations, some based on new data, constrain the hypothesis. First, the limit of normal oceanic crust coincides with a landward-dipping basement ramp near the seaward end of the salt basin, which has been mapped on seismic data. Second, the deep salt in the deep-water Gulf of Mexico can be separated into provinces on the basis of position with respect to this ramp. Third, paleodepths in the postsalt sequence indicate that salt filled the Gulf of Mexico salt basin to near sea level. Fourth, seismic data show that postsalt sediments in the central Louann and the Yucatan salt basins exhibit large magnitudes of Late Jurassic salt-detached extension not balanced by equivalent salt-detached shortening. In our hypothesis, Callovian salt was deposited in preexisting crustal depressions on hyperextended continental and transitional crust. After salt deposition ended, rifting continued for another 7 to 12 m.y. before sea-floor spreading began. During this phase of postsalt crustal stretching, the salt and its overburden were extended by 100 to 250 km (62–155 mi), depending on location. Sea-floor spreading divided the northern Gulf of Mexico into two segments, separated by the northwest-trending Brazos transform. The eastern segment opened from east to west, leaving the Walker Ridge salient in the center of the basin as the final area to break apart. In some areas, salt flowed seaward onto new oceanic crust, first concordantly over the basement as a parautochthonous province, then climbing up over stratigraphically younger strata as an allochthonous province.
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  • 28
    Publication Date: 2013-10-04
    Description: Three aspects of basement structure and rift-related salt distribution have especially influenced the evolution of the deep-water northern Gulf of Mexico: (1) creation of a basement high (Toledo Bend flexure), separating a chain of interior basins from the central Louann salt basin, (2) segmentation of the central Louann salt basin by the Brazos transfer fault into eastern and central domains, and (3) salt provinces formed during basin opening. The Toledo Bend flexure was reactivated as a hinge during the Cenozoic uplift of the North American craton. This uplift triggered gravity gliding, forming fold belts in the seaward parts of the continental margin. The geometry of the Toledo Bend flexure influenced the position of these fold belts. The Brazos transfer fault separates the west sector of the study area from the central and east sectors. Most of the salt in the deep-water northern Gulf of Mexico lay in the central sector, which sourced most of the Sigsbee salt canopy. The western sector was narrower and was subdivided by the East Breaks basement high. Splitting the Callovian salt basin in two as the gulf opened created a southward-thinning wedge of salt at the seaward end of the northern Gulf of Mexico. We divide this wedge into a series of provinces on the basis of the geometry of the base of the deep salt. Original salt thickness influenced diapir location, the geometry of the Sigsbee canopy, the geometry and style of later compressional fold belts, and petroleum systems.
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  • 29
    Publication Date: 2013-10-04
    Description: Recent ultradeep exploration in the northern Gulf of Mexico has revealed a broad diffuse zone of salt-cored folding beneath the present continental shelf. This zone is a pillow fold belt, where salt pillows grew halokinetically and were then mildly shortened. Below the Louisiana shelf, a contractional early-to-late Miocene pillow fold belt is separated by a partly welded canopy from an overlying early Miocene–to–Pliocene extensional system. This anomalous juxtaposition raises two paradoxes: (1) Why was mid-Miocene shortening close to the Miocene shelf break, where extension is expected? and (2) Why did shortening below the canopy overlap in time with extension above the canopy? Coastal uplift can explain both paradoxes. Cenozoic uplift and exhumation of the north rim of the Gulf of Mexico created the observed coastal offlap and truncation around the rim. Uplift tilted the continental margin and overpowered the influence of the paleoshelf break, causing shortening much farther updip than before uplift. Physical models confirm that this hypothesis is mechanically sound. Our other models had two stacked detachments, each pinned in different locations. Because of this, deep shortening below the canopy was coeval with shallow extension above the canopy. The deep detachment was pinned far inland, equivalent to the uplifted continental interior. Extension above this deep detachment was partly balanced by shortening far downdip to form a pillow fold belt where a network of thrusts linked the squeezed pillows. In contrast, the shallow extensional system above the canopy was pinned farther seaward, equivalent to the upper continental slope.
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  • 30
    Publication Date: 2013-10-04
    Description: The process and mechanisms of secondary hydrocarbon migration in the Tazhong uplift, Tarim Basin, were investigated based on the analysis of the regional structure and by integrating geologic, hydrodynamic, and geochemical parameters. Parameters successfully analyzed included the fluid potential, fluid properties, production outputs, and diamantane index. The results indicated that hydrocarbons migrated into the Tazhong uplift from the northern part of the Manjiaer depression through a series of injection points (IPs) during four orogenies, that is, the early Caledonian (510 Ma), the late Caledonian (439 Ma), the late Hercynian–Indosinian (290 Ma), and the Yanshanian–Himalayan (208 Ma). A total of six IPs were identified at the intersections of the northeast-trending faults and the northwest-trending flower strike faults. The hydrocarbons migrated from the IPs into traps along regional trends from northwest to southeast and from northeast to southwest. The hydrocarbon migration process and patterns determined the distribution of hydrocarbon properties and production rates in the Tazhong uplift. With increasing distance from the IPs, daily hydrocarbon production decreases, and the hydrocarbons become progressively heavier and display lower gas:oil ratios.
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  • 31
    Publication Date: 2013-10-04
    Description: Determination of turbidite event magnitude and frequency remains subjective and difficult to define. This is because turbidite sedimentation events commonly include both sand and mud, with the mud component commonly excluded from bed thickness studies because of the inability to establish a genetic link to the turbidity current. Pelagic mudrock is defined as fine-grained marine sediment derived primarily from biogenic particles, whereas hemipelagic mudrock includes both biogenic and terrigenous particles. Unfortunately, these compositional definitions do not account for differences in depositional process. Scanning electron microscopy, field emission scanning electron microscopy, and x-ray diffraction analyses of 70 samples from El Rosario Formation outcrops (Baja California, Mexico) and core from the Woodford Shale (Oklahoma) illustrate this distinction. Furthermore, these laboratory measurements are calibrated to 192 outcrop samples to provide a robust method for field identification of clay fabric and mineralogy to define turbidite sedimentation units. Pelagites show organized layering of clay platelets, few flocculates, and a lower proportion of high-density minerals. Hemipelagites have disorganized and chaotic clay fabrics characterized by visible flocculates and contain a higher proportion of denser particles. There may also be a corresponding change in clay mineralogy, for example, smectite in pelagites versus kaolinite in hemipelagites. These results indicate a settling velocity greater than shear velocity in pelagites, whereas hemipelagites record the opposite condition. Turbidity currents support and suspend denser grains, generate disorganized and chaotic clay fabrics, and provide more time for flocculation. Discrimination between pelagites and hemipelagites has important implications in the determination of turbidite event frequency and magnitude, which affects vertical connectivity and continuity of sand, deposited from multipartite turbidity currents. In addition, distinction between pelagites and hemipelagites provides a better understanding of mudrock reservoir architecture.
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  • 32
    Publication Date: 2013-10-04
    Description: The Molasse deposits of the Central Eastern Alps are partly incorporated into a fold and thrust belt that recently has come into exploration focus. The structural style and timing of deformation varies significantly alongstrike. Regional three-dimensional seismic and well data interpretation indicate three different structural segments from east to west: (1) The Sierning imbricates have a decollement close to the base of the Molasse sequence and consist of varying numbers of thrust sheets alongstrike. Early Miocene shortening of the Molasse is at least 6.2 km (3.9 mi). Overthrusting of the internal Penninic and Helvetic wedge since the Oligocene accommodated at least 25 km (15.5 mi) of additional shortening. (2) The Regau segment is dominated by one to two small thrust sheets above a shallow detachment. This segment is dominated by overthrusting of the Alpine wedge. (3) The Perwang imbricates consist of an Oligocene wedge with complex deformed thrust sheets above a detachment horizon in Upper Cretaceous marls. Minimum shortening in the imbricates is 18.5 km (11.5 mi) with overthrusting 33.3 km (20.7 mi). All shortening estimates have an uncertainty of approximately 20% to 35%. The laterally varying thrust-belt architecture results from predeformational conditions (e.g., sediment thickness, mechanical stratigraphy, and basement dip). In the Sierning imbricates, hydrocarbon trap definition and charge issues are exploration risks. In the Regau segment, exploration is focused on the subthrust play. The Perwang imbricates have hydrocarbon shows but no economic discoveries. Charge and seal issues are the main risks. The petroleum systems in the context of the structural evolution are not yet fully understood.
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  • 33
    Publication Date: 2013-09-14
    Description: Quartz is the principal framework mineral in clastic sediment reservoirs. In a frontier basin with sparse wells, the source of quartz in sandstones may be a predictor of the availability of medium- to coarse-grained quartz sand from plutonic sources, likely to provide good reservoirs. The Scotian Basin, offshore eastern Canada, was used to test this hypothesis because of its well-understood provenance history and geographic variability in known medium- to coarse-grained reservoir sandstones. The sources of detrital quartz in fine-grained sandstones were determined using hot-cathode cathodoluminescence (CL), supplemented by other petrographic techniques. The CL color shift for different quartz types was calibrated against the CL properties of representative source rocks in the hinterland, because generalizations in the literature do not precisely match our basin-specific observations. Grain size of sandstone exerts a strong control over quartz type, with plutonic-hypabyssal quartz and high-grade metamorphic quartz more abundant in coarse-grained sandstones and low-grade metamorphic quartz more abundant in fine-grained sandstones. Nevertheless, the analysis of fine-grained sandstones shows that plutonic-hypabyssal quartz is more abundant in fine-grained sandstones of the Sable subbasin than in those of the Abenaki subbasin. The abundance of plutonic-hypabyssal quartz correlates with the abundance of medium- to coarse-grained sandstone reservoirs in the Sable subbasin. This study suggests that, in frontier basins, the abundance of plutonic-hypabyssal quartz in fine-grained sandstones can be used as an indicator of available medium- to coarse-grained sandstone reservoir.
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  • 34
    Publication Date: 2013-09-14
    Description: The three-dimensional (3-D) geometry of fractures and fault-related dolomite is difficult to access with classical subsurface prospection tools. Therefore, we have investigated an outcrop to improve the subsurface prediction for complex dolomite bodies. This outcrop is located in the Etoile massif (southeastern France) within a fault-bend anticline. The sedimentary units are of Upper Triassic to lower Barremian age. The fold results from the Pyreneo-Provençal shortening during the Late Cretaceous to the Eocene. The anticline hosts three types of dolomite bodies: (1a) massive dolomite of middle to late Oxfordian age, (1b) syndepositional stratabound dolomite of Tithonian age, and (2) isolated dolomite bodies associated with fractures and faults. Large-scale geometries of fault-related dolomite bodies have been modeled in 3-D. The 3-D geometries of these bodies show diapir-, finger- and wall-like structures. These bodies are located close to the main thrusts, in strata of middle Oxfordian to early Barremian age and are linked to the compressive fold-bending phase during the Late Cretaceous. Fault-related dolomitization occurred because of magnesium removal from the hydraulic brecciation and the pressure solution of type 1 dolomite with overpressured fluids. These fluids flushed upward along the main thrust and laterally by following the reservoir property contrasts in the host rocks. Fault-related dolomite bodies are either spread far apart from faults in grainy limestones with good initial reservoir properties or are restricted to fault vicinity in muddy limestones with poor initial reservoir properties. The study of the structural and stratigraphic framework was essential in the understanding of the dolomitization process.
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  • 35
    Publication Date: 2013-10-04
    Description: An interpretation of geologic structure at King Sound in the Canning Basin was completed using airborne gravity gradient, magnetic, and seismic data. During the Late Devonian and Mississippian periods, the elevated part of the basement in the north was rimmed by carbonate reefs and redeposited carbonate debris, whereas in the south, siliciclastic submarine fans and turbidites were deposited along the margin of the basement in a deep-marine environment. Three principal lithologic units were identified from the vertical gravity gradient ( G DD ) in the basin: (1) the Fairfield Group carbonates of high density are interpreted to be the source of prominent positive gravity anomalies; (2) forereef debris and carbonate clastics reworked from carbonates higher up the slope or from the carbonate platform are interpreted to be the source of medium-density responses; and (3) turbidites, debris flows, and associated clastic basinal sequences of low density are interpreted to be the source of prominent negative gravity anomalies. Depth slices of G DD indicate the channelized nature of turbidite flows. In the lower section of the basin, intrasedimentary intrusives were identified from magnetic, G DD , seismic, and well data. Depth to magnetic basement calculation indicates that the surface of the Archean to Paleoproterozoic basement ranges from 3200 to 130 m (10,499–427 ft) below sea level. The northwest- and northeast-oriented south-dipping faults cut the basement and propagate upward into the sediments. A three-dimensional geologic model constructed for King Sound satisfies all known geologic constraints and is consistent with the gravity, magnetic, seismic, and well data.
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  • 36
    Publication Date: 2013-10-04
    Description: The evolution of porosity in shales with increasing maturity was examined in a suite of five New Albany Shale samples spanning a maturity range from immature (vitrinite reflectance, R o 0.35%) to postmature (R o 1.41%). Devonian to lower Mississippian New Albany Shale samples from the Illinois Basin used in this study contain marine type II kerogen having total organic carbon contents from 1.2 to 13.0 wt. %. Organic petrology, CO 2 and N 2 low-pressure adsorption, and mercury intrusion capillary pressure techniques were used to quantify pore volumes, pore sizes, and pore-size distributions. Increasing maturity of the New Albany Shale is paralleled by many changes in the characteristics of porosity. The total porosity of 9.1 vol. % in immature New Albany Shale decreases to 1.5 vol. % in the late mature sample, whereas total pore volumes decrease from 0.0365 to 0.0059 cm 3 /g in the same sequence. Reversing the trend at even higher maturity, the postmature New Albany Shale exhibits higher porosity and larger total pore volumes compared to the late mature sample. With increasing maturity, changes in total porosity and total pore volumes are accompanied by changes in pore-size distributions and relative proportions of micropores, mesopores, and macropores. Porosity-related variances are directly related to differences in the amount and character of the organic matter and mineralogical composition, but maturity exerts the dominant control upon these characteristics. We conclude that organic matter transformation due to hydrocarbon generation and migration is a pivotal cause of the observed porosity differences.
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  • 37
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2013-10-04
    Description: In this case study, we used simulated seismic data from outcrops on Svalbard to analyze what seismic facies are composed of, what the dominating factors in forming the facies are, and which consequences this has for the interpretation results. Seismic facies analyses can be used to interpret environmental setting, depositional processes, and lithology. Here, we found that noise is the most important factor in forming the seismic facies. Noise is defined as all reflections that cannot be ascribed directly to the reservoir model. Effects from overburden and processing dominated, and the low-frequency content of the seismic section complicated the seismic facies analyses. The main reason for this is that the analysis relies heavily on identified internal patterns and low-angle terminations. Such patterns and terminations are easily created by the seismic method itself, by overburden effects, and by artifacts generated when processing the data. External form, strong amplitudes, and continuous reflections are robust seismic observations, whereas the internal pattern and terminations are commonly deceptive. Identification of boundaries based on predefined patterns of terminations does not work here, and uncritical use of seismic facies analysis in this interpretation case will create wrong reservoir models. Because of the size of the outcrops, the results from this analysis are relevant for reservoir-scale seismic interpretation and detailed interpretation for prospect evaluation in mature basins. For seismic interpretation at a more regional scale, it is probably less relevant.
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  • 38
    Publication Date: 2013-10-04
    Description: The Ordovician carbonate platform at the Yijianfang outcrop of the Bachu uplift region in the western Tarim Basin contains four types of genetic facies associations developed in the calciclastic slope-fan depositional system: an olistostrome zone, fan channels, lobes, and a marginal slope. The olistostrome zone is characterized by olistoliths and slump fans, whereas the fan channels and lobes are further divided into proximal and distal facies. The marginal slope deposits constitute the background sedimentation in which the calciclastic slope fans are intercalated. From proximal to distal parts of the fan channels and lobes, their scale gradually becomes smaller, and the size and sorting of grains become finer and better, respectively. Analysis of the stratigraphic framework indicates that the fans formed in the lower strata of the Upper Ordovician Lianglitage Formation in four high-frequency sequences (i.e., Pss1–Pss4). Field paleocurrent measurements indicate northeast-southwest depositional strike for the early platform margin of the Lianglitage Formation. Sediments in the calciclastic slope fans were derived from the platform margin, and evolution of the calciclastic slope fans was generally progradational from Pss1 to Pss2 and then continuously retrogradational from Pss2 to Pss4. The calciclastic slope fans in the outcrop area are not reservoir-prone rocks, but interpretation on these fans can provide useful information about potential hydrocarbon reservoirs along the platform margin. The P -wave velocity, S -wave velocity, and density variations in each genetic facies may be used to identify the subsurface calciclastic slope-fan depositional system.
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  • 39
    Publication Date: 2013-04-04
    Description: Reservoir properties of Upper Triassic–Middle Jurassic sandstones, Spitsbergen, are studied as part of a CO 2 storage pilot project in Longyearbyen. The reservoir formations show large contrasts in sandstone compositions, with unexpected low permeability despite moderate porosity values. Petrographic analyses were performed to investigate the influence and distribution of diagenesis. It is concluded that, because of various compaction, cementation, and dissolution processes, the sandstone porosity is mainly isolated molds and micropores and associated with fibrous illite and chamosite, explaining the low permeability. Diagenesis and the distribution of quartz cement is influenced by lithofacies and detrital compositions. Mineralogically immature sandstones (De Geerdalen Formation) show a homogeneous distribution of quartz cement overgrowths on quartz grains, distributed interstitial to labile grains and other cements (e.g., late calcite). The main silica source was from the dissolution of adjacent feldspar and labile grains as part of the chemical compaction. In contrast, quartz-dominated sandstones (Knorringfjellet Formation) show a heterogeneous patchy distribution of quartz cement influenced by the sedimentary bioturbation pattern, with silica sourced also from dissolution at clay-rich microstylolites. Phosphatic beds at the base and top of the formation are strongly influenced by marine eogenesis and reworking processes and associated with concentration of iron-rich authigenic minerals. The highest porosity appears in sand-supported conglomerate where moldic clay-mineral ooids contributed to reduce quartz cementation. The stratigraphic change from mineralogical immature (Triassic) to mature (uppermost Triassic–Jurassic) sandstone compositions is detected in wide areas of the Barents Shelf and has considerable implications for the distribution of sandstone reservoir properties.
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  • 40
    Publication Date: 2013-09-14
    Description: Innovative seismic forward modeling is used to illustrate the sensitivity within seismic data, and its application in the interpretation of onlap and pinch-out of terminating deep-water sandstones, two critical components in deep-water exploration and production. Sandstone quality, net-to-gross estimates, volume calculations, vertical connectivity, and stratigraphic trapping are all dependent on the sandstone extent and their seismic characteristics in these settings. However, seismic resolution is commonly insufficient to resolve the critical reservoir parameters. Seismic modeling of termination styles based on integrated outcrop and subsurface properties allows for depth- and resolution-focused predictive models to be built for improved subsurface analysis. This technique is currently underused as a method to better understand the sensitivity of seismic data to the target lithologies and their geometries. The Grès d'Annot Formation is a well-studied sand-prone deep-water system of Paleogene age, deposited in a bathymetrically complex setting. Six end-member termination styles are discussed, including three sand-prone styles—simple onlap (O s ), draping onlap (O d ), and bed thickening (O t )—and three heterolithic styles—advancing pinch-out (P a ), convergent pinch-out (P c ), and convergent thickening and pinch-out (P ct ). Local thickening close to the system margins is common in both sand-prone and heterolithic terminating strata and plays an important function in the appropriate distribution of sandstone. The outcrops are interpreted as potential (process) analogs for the complex sandstone distribution and termination patterns observed in plays like the Paleogene of the Gulf of Mexico and the Jurassic of the northern North Sea.
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  • 41
    Publication Date: 2013-09-14
    Description: Cenozoic rifted lacustrine basins in east China display three main basin types: (1) basins with steeply dipping boundary fault, whose hanging walls tilt along pivot points; (2) basins with listric boundary faults, whose hanging walls bend along flexural bending points; and (3) basins formed by earlier extensional rifting with later strike-slip movement superimposed. The sequence development is intimately linked to the tectonic movements in the area, where second-order sequences are regionally correlatable from basin to basin and relate to the large-scale tectonic movements in the region. Third-order sequences are related to local tectonic activity and are correlatable within basins, between subbasins, and sometimes, between neighboring basins. Detailed sequence-stratigraphic analysis and mapping of depositional systems demonstrate that sand-body distribution patterns are related to sequence-stratigraphic frameworks. For the three kinds of basins, the positions of pivot point zones, flexural bend zones, and strike-slip faults plus the syndepositional faults all control the distribution of depositional systems, systems tract, and sand bodies. These controlling factors can be attributed to different structural and stratigraphic features that change the accommodation. Structural elements include boundary faults, syndepositional faults, and abrupt changes in dip. Stratigraphic controls include preexisting surfaces with local channelization, paleobathymetric lows, and onlap onto clinoform slopes. The lowstand sand bodies deposited at the downdip end of these controlling factors constitute the current and future exploration targets for conventional reservoirs.
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  • 42
    Publication Date: 2013-09-14
    Description: Outcrops provide valuable information for the characterization of fracture networks. Sampling methods such as scanline sampling, window sampling, and circular scanline and window methods are available to measure fracture network characteristics in outcrops and from well cores. These methods vary in their application, the parameters they provide and, therefore, have advantages and limitations. We provide a critical review on the application of these sampling methods and apply them to evaluate two typical natural examples: (1) a large-scale satellite image from the Oman Mountains, Oman (120,000 m 2 [1,291,669 ft 2 ]), and (2) a small-scale outcrop at Craghouse Park, United Kingdom (19 m 2 [205 ft 2 ]). The differences in the results emphasize the importance to (1) systematically investigate the required minimum number of measurements for each sampling method and (2) quantify the influence of censored fractures on the estimation of fracture network parameters. Hence, a program was developed to analyze 1300 sampling areas from 9 artificial fracture networks with power-law length distributions. For the given settings, the lowest minimum number of measurements to adequately capture the statistical properties of fracture networks was found to be approximately 110 for the window sampling method, followed by the scanline sampling method with approximately 225. These numbers may serve as a guideline for the analyses of fracture populations with similar distributions. Furthermore, the window sampling method proved to be the method that is least sensitive to censoring bias. Reevaluating our natural examples with the window sampling method showed that the existing percentage of censored fractures significantly influences the accuracy of inferred fracture network parameters.
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  • 43
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2013-09-14
    Description: In western Greece, the Ionian and pre-Apulian zones represent, respectively, the basin and the transitional zone (slope) to the Apulian platform. The Apulian platform constitutes the weakly deformed foreland of the external Hellenides. The pre-Apulian zone appears in the Ionian Islands and the eastern Ionian Sea, whereas the Apulian platform is exclusively found in the Ionian Sea. The Ionian zone consists of Triassic evaporites, Jurassic–upper Eocene (mostly pelagic carbonates, minor cherts, and shales), overlain by the Oligocene flysch. Organic-rich source rocks occur within Triassic evaporites and Jurassic–Cretaceous pelagic argillaceous-siliceous rocks. The pre-Apulian zone consists of Triassic to Miocene deposits, mainly mixed neritic-pelagic carbonates. Hydrocarbon source rocks include pelagic and hemipelagic deposits rich in marine organic material, although terrigenous organic matter is also found in siliciclastic layers. Apulian platform source rocks are mainly the organic-rich shales within the Triassic Burano evaporites. Western Greece contains major petroleum systems, which extend into the Ionian Sea. Ionian, pre-Apulian, and Apulian petroleum systems contribute to the probable hydrocarbon accumulations within the big offshore (Ionian Sea) anticlines. Western Greece contains important oil and gas shale reservoirs with a potential of unconventional exploration. Promising areas for hydrocarbons need systematic and detailed three-dimensional seismic data. Exploration for conventional petroleum reservoirs, through the interpretation of seismic profiles and the abundant surface geologic data, will provide the subsurface geometric characteristics of the unconventional reservoirs. Their exploitation should follow that of conventional hydrocarbons to benefit from the anticipated technological advances, eliminating environmental repercussions.
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  • 44
    Publication Date: 2015-05-05
    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.
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  • 45
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2015-05-05
    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.
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  • 46
    Publication Date: 2015-05-05
    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.
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  • 47
    Publication Date: 2015-05-05
    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.
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  • 48
    Publication Date: 2015-05-05
    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.
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  • 49
    Publication Date: 2015-05-05
    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.
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  • 50
    Publication Date: 2015-05-05
    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.
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  • 51
    Publication Date: 2015-04-07
    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).
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  • 52
    Publication Date: 2015-04-07
    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.
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  • 53
    Publication Date: 2015-04-07
    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.
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  • 54
    Publication Date: 2016-03-29
    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.
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  • 55
    Publication Date: 2016-03-29
    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.
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  • 56
    Publication Date: 2019
    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〉
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  • 57
    Publication Date: 2019
    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〉
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  • 58
    Publication Date: 2019
    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〉
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  • 59
    Publication Date: 2019
    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〉
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  • 60
    Publication Date: 2019
    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〉
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  • 61
    Publication Date: 2019
    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〉
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  • 62
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    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〉
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  • 63
    Publication Date: 2019
    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〉
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  • 64
    Publication Date: 2018
    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〉
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  • 65
    Publication Date: 2018
    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〉
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  • 66
    Publication Date: 2018
    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〉
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  • 67
    Publication Date: 2018
    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〉
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  • 68
    Publication Date: 2018
    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〉
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  • 69
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2018
    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〉
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  • 70
    Publication Date: 2018
    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〉
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  • 71
    Publication Date: 2018
    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〉
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  • 72
    facet.materialart.
    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2018
    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〉
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  • 73
    Publication Date: 2018
    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〉
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  • 74
    Publication Date: 2018
    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〉
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  • 75
    Publication Date: 2018
    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〉
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  • 76
    Publication Date: 2018
    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〉
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  • 77
    Publication Date: 2018
    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〉
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  • 78
    Publication Date: 2018
    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〉
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  • 79
    Publication Date: 2018
    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〉
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  • 80
    Publication Date: 2018
    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〉
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  • 81
    Publication Date: 2018
    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〉
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  • 82
    Publication Date: 2018
    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〉
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  • 83
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2018
    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〉
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
    Topics: Geography , Geosciences
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  • 84
    Publication Date: 2018
    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〉
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  • 85
    Publication Date: 2018
    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〉
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  • 86
    facet.materialart.
    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2018
    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〉
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  • 87
    facet.materialart.
    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2018
    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〉
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  • 88
    Publication Date: 2018
    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〉
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  • 89
    Publication Date: 2018
    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〉
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  • 90
    Publication Date: 2018
    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〉
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  • 91
    Publication Date: 2018
    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〉
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  • 92
    Publication Date: 2018
    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〉
    Print ISSN: 0149-1423
    Electronic ISSN: 1943-2674
    Topics: Geosciences
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  • 93
    Publication Date: 2019
    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〉
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  • 94
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    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    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〉
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  • 95
    Publication Date: 2019
    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〉
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  • 96
    Publication Date: 2019
    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〉
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  • 97
    Publication Date: 2019
    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〉
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  • 98
    Publication Date: 2019
    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〉
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  • 99
    Publication Date: 2019
    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〉
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  • 100
    facet.materialart.
    Unknown
    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2019
    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〉
    Print ISSN: 1075-9565
    Electronic ISSN: 1526-0984
    Topics: Geography , Geosciences
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