Showing papers in "AAPG Bulletin in 2003"

Practical approaches to identifying sealed and open fractures

Abstract: For one essential ingredient of permeable fracture networks (degree of fracture pore-space preservation in large fractures), I show how the characterization challenge presented by sparse fracture sampling can be overcome by measuring a surrogate, the abundance of rock-mass cement that precipitated after fractures ceased opening. Sampling limitations are overcome because the surrogate is readily measured in small rock samples, including sidewall cores and cuttings, permitting site-specific diagnosis of the capacity of fractures to transmit fluid over a wider range of sample depths than conventional methods allow. A diverse core database shows that this surrogate correctly predicts where large fractures are sealed. Information on timing of fracture opening relative to cement sequence can be obtained in two ways. First, evidence of fracture-movement history and cement sequences in sparse large fractures can be extrapolated to areas having only cement data. Alternately, evidence of fracture timing can be acquired from sealed, micrometer-scale fractures. Distribution of porosity-reducing cement is commonly heterogeneous (from bed to bed and location to location) in siliciclastic and carbonate rocks. However, because patterns of sealed or open fractures cannot be delineated using fracture observations alone, surrogates have practical value for production fairway mapping and other applications in which identifying open fractures is essential. This study highlights the vital interplay among structural and diagenetic processes for fracture-porosity preservation or destruction.

Prolific deep-marine slope channels of the Nile Delta, Egypt

Abstract: The Nile Delta offshore is rapidly emerging as a major gas province. High-quality three-dimensional (3-D) seismic data, coupled with data from 13 consecutive successful deep-water exploration and appraisal wells, have highlighted clear phases of erosion and deposition within the upper Pliocene deep-marine slope channels. The gross reservoir architecture is spectacularly imaged by 3-D seismic techniques, both in time sections and through a variety of amplitude extractions, while an extensive program of core and wire-line log acquisition and analysis has enabled high-resolution definition of the channel-fill sediments. The channels were initiated by the introduction of coarse sediments to the shelf edge possibly at times of relative sea level fall. Initially, there was significant erosion, especially in areas up depositional dip, creating what we term slope valleys. Subsequent valley infill commonly commenced with debris flows, slumps, and slides, sometimes overlying basal, bypass-related sands, and progressed to amalgamated or stacked channels in packages of upward-decreasing net-to-gross sand ratios. This pattern was commonly repeated following reincision, which may have occurred several times. The different stages of channel development can be considered in terms of slope equilibrium with a reduction in slope gradient promoted by increases in flow size and density and decreases in grain size.

Microbial production and modification of gases in sedimentary basins: A geochemical case study from a Devonian shale gas play, Michigan basin

Abstract: An expanded data set for gases produced from the Antrim Shale, a Devonian black shale in the Michigan basin, United States, has allowed for a detailed examination of the related chemical and isotopic compositional changes in the solid-gas-liquid systems that discriminate between microbial and thermogenic gas origin. In the Antrim Shale, economic microbial gas deposits are located near the basin margins where the shale has a relatively low thermal maturity and fresh water infiltrates the permeable fracture network. The most compelling evidence for microbial generation is the correlation between deuterium in methane and coproduced water. Along the basin margins, there is also a systematic enrichment in 13C of ethane and propane with decreasing concentrations that suggests microbial oxidation of these thermogenic gas components. Microbial oxidation accounts not only for the shift in 13C values for ethane, but also, in part, for the geographic trend in gas composition as ethane and higher chain hydrocarbons are preferentially removed. This oxidation is likely an anaerobic process involving a syntrophic relationship between methanogens and sulfate-reducing bacteria.The results of this study are integrated into a predictive model for microbial gas exploration based on key geochemical indicators that are present in both gas and coproduced water. One unequivocal signature of microbial methanogenesis is the extremely positive carbon isotope values for both the dissolved inorganic carbon in the water and the coproduced CO2 gas. In contrast, the 13C value of methane is of limited use in these reservoirs as the values typically fall between the commonly accepted fields for thermogenic and microbial gas. In addition, the confounding isotopic and compositional overprint of microbial oxidation, increasing the values to typically thermogenic values, may obscure the distinction between methanogenic and thermogenic gas.

Geochemical signature of formation waters associated with coalbed methane

Abstract: Formation waters associated with coalbed methane have a common chemical character that can be an exploration tool, regardless of formation lithology or age. Effectively devoid of sulfate, calcium, and magnesium, the waters contain primarily sodium and bicarbonate and, where influenced by water of marine association, also contain chloride. The distinct geochemical signature evolves through the processes of biochemical reduction of sulfate, enrichment of bicarbonate, and precipitation of calcium and magnesium. Cation exchange with clays may also deplete the dissolved calcium and magnesium, but is not prerequisite. Low sulfate/bicarbonate ratios characterize these waters and are also common but less pronounced with occurrences of conventional oil and gas. Waters rich in sulfate, calcium, and magnesium occur in many coalbed aquifers but are not found in association with methane. Users of total dissolved solids data should ensure that the values reflect adjustments of bicarbonate concentrations to simulate evaporation residues. Results that erroneously sum the entire bicarbonate content can be far too high in these bicarbonate-rich waters, thereby exacerbating the issues of disposal. Evaluations of prospects and choices of exploration targets can be enhanced by an added focus on the geochemical signature that should be expected in association with methane. Knowledge of the geochemical signature may also be useful in the commonly protracted testing of wells. The appearance of high sulfate concentrations in water analyses can justify early curtailment of test pumping and can prompt the siting of subsequent drill holes farther from areas of recharge.

Subandean thrust and fold belt of northwestern Argentina: Geometry and timing of the Andean evolution

Abstract: The Subandean ranges of northwestern Argentina are an active thin-skinned fold and thrust belt. The main detachment level in Silurian shales dips 2–3W, and all the major east-verging faults detach from it. Important intermediate detachment levels in the Devonian shales generate lift-off structures and the decoupling of the lower and upper structural levels. The Subandean thrust belt has a minimum shortening of about 60 km (36%) at about 2240 latitude. The deformation started at about 8.5–9 Ma with the uplift of the El Pescado range and the formation of an important back thrust at the Cinco Picachos range. Fault generation gets young to the east; the Pintascayo range uplift started at 7.6 Ma, while the Baja Orn range uplift began at about 6.9 Ma. These two ranges continued growing simultaneously until at least 4.7 Ma. At San Antonio range, fault movement began at approximately 4.4 Ma, and the Aguarage uplift started at about 2.7 Ma. An important stage dominated by out-of-sequence movements spans from about 4.5 Ma to present. For both proposed models of shortening, the Quaternary rates of shortening between 8 and 11 mm/yr coincide well with global positioning system results from the area. The hydrocarbon generation and migration is contemporaneous with the deformation, enhancing the possibilities of hydrocarbon entrapment in the area.

Brittle-failure controls on maximum sustainable overpressure in different tectonic regimes

Abstract: Formation or reactivation of brittle faults and fractures within low-permeability rocks capping regions of overpressured crust creates drainage conduits limiting the degree of overpressuring. Maximum sustainable overpressure is therefore affected by the local state of stress within the capping layer and by any existing architecture of faults and fractures. Reshear of existing cohesionless faults that are favorably oriented for frictional reactivation within the stress field provides the lower limiting bound to overpressures and inhibits development of other brittle structures. Formation of drainage conduits by hydraulic extension fracturing is important only in the case of intact caprock under low differential stress. Brittle-failure-mode plots demonstrate that maximum overpressure is inversely related to the level of differential stress and that high overpressures are easier to sustain in compressional regimes. Changes in the regional stress state in areas of overpressuring (for example, during tectonic inversion) may induce significant fluid redistribution.

Near-salt deformation in La Popa basin, Mexico, and the northern Gulf of Mexico: A general model for passive diapirism

Abstract: Strata adjacent to exposed diapirs in La Popa basin, northeastern Mexico, comprise stacked halokinetic sequences consisting of unconformity-bounded packages of thinned and rotated strata cut by radial faults. Deformation results from shallow drape folding over the flanks of the rising diapirs and not from deep drag folding in diapir-peripheral shear zones. Subsurface analogs from the Gulf of Mexico have diapir-flanking geometries ranging from similar, wide zones of upturned and thinned strata to undeformed, constant-thickness strata. Subhorizontal salt tongues display little subsalt deformation and thinning.We propose a general model for passive diapirism and flank deformation that includes (1) gradually varying salt-flow rates, (2) superposed episodic sedimentation that results in changing bathymetric relief, (3) rotation of near-surface strata as salt inflates relative to the adjacent basin, (4) failure and erosion of strata in the steepening bathymetric halo, and (5) bedding-parallel slip surfaces that converge on unconformities and onlap surfaces. A primary factor influencing flank geometries is the width of the bathymetric high extending beyond the diapir edge. This is largely dependent on the thickness of the halokinetic sequence onlapping the diapir, which in turn is controlled mostly by the interplay between salt inflation/deflation rates and sedimentation rates. Other factors include the amount of concurrent shortening, which produces a wider but less intense zone of deformation, and the position on the scarp of salt breakout and extrusion.Our model is important for exploration and production in diapir-flank and subsalt settings because of its implications for trap size and geometry, reservoir distribution, trap compartmentalization and pressure seals, and hydrocarbon charge. It can help in explaining complex and enigmatic well data and in better assessing risk in areas of poor seismic imaging.

Petroleum geology and potential hydrocarbon plays in the Gulf of Suez rift basin, Egypt

Abstract: The Gulf of Suez in Egypt has a north-northwest–south-southeast orientation and is located at the junction of the African and Arabian plates where it separates the northeast African continent from the Sinai Peninsula. It has excellent hydrocarbon potential, with the prospective sedimentary basin area measuring approximately 19,000 km 2 , and it is considered as the most prolific oil province rift basin in Africa and the Middle East. This basin contains more than 80 oil fields, with reserves ranging from 1350 to less than 1 million bbl, in reservoirs of Precambrian to Quaternary age. The lithostratigraphic units in the Gulf of Suez can be subdivided into three megasequences: a prerift succession (pre-Miocene or Paleozoic–Eocene), a synrift succession (Oligocene–Miocene), and a postrift succession (post-Miocene or Pliocene–Holocene). These units vary in lithology, thickness, areal distribution, depositional environment, and hydrocarbon importance. Geological and geophysical data show that the northern and central Gulf of Suez consist of several narrow, elongated depositional troughs, whereas the southern part is dominated by a tilt-block terrane, containing numerous offset linear highs. Major prerift and synrift source rocks have potential to yield oil and/or gas and are mature enough in the deep kitchens to generate hydrocarbons. Geochemical parameters, sterane distribution, and biomarker correlations are consistent with oils generated from marine source rocks. Oils in the Gulf of Suez were sourced from potential source rock intervals in the prerift succession that are typically oil prone (type I), and in places oil and gas prone (type II), or are composites of more than one type (multiple types I, II, or III for oil prone, oil and gas prone, or gas prone, respectively). The reservoirs can be classified into prerift reservoirs, such as the Precambrian granitic rocks, Paleozoic–Cretaceous Nubian sandstones, Upper Cretaceous Nezzazat sandstones and the fractured Eocene Thebes limestone; and synrift reservoirs, such the Miocene sandstones and carbonates of the Nukhul, Rudeis, Kareem, and Belayim formations and the sandstones of South Gharib, Zeit, and

New insights on the Green River petroleum system in the Uinta basin from hydrous pyrolysis experiments

Abstract: The Tertiary Green River petroleum system in the Uinta basin generated about 500 million bbl of recoverable, high pour-point, paraffinic crude oil from lacustrine source rocks. A prolific complex of marginal and open-lacustrine source rocks, dominated by carbonate oil shales containing up to 60 wt. % type I kerogen, occur within distinct stratigraphic units in the basin. Petroleum generation is interpreted to originate from source pods in the basal Green River Formation buried to depths greater than 3000 m along the steeply dipping northern margin of the basin. Producing fields in the Altamont-Bluebell trend have elevated pore-fluid pressures approaching 80% of lithostatic pressure and are completed in strata where open fractures provide permeability. Active hydrocarbon generation is one explanation for the origin of the overpressured reservoirs. In this study, experiments were undertaken to examine the mechanisms of hydrocarbon generation and accumulation in the Uinta basin. We combined analyses of representative source rocks from the entire Green River stratigraphic section with detailed laboratory simulation experiments using both open- and closed-system pyrolysis. This information provides new insights on lacustrine source rock lithofacies, gas-oil-source rock correlations, hydrocarbon generation kinetics, and basin modeling. The results show that the basal Green River Formation contains a unique type I source facies responsible for generation of paraffinic crude oils. The classic type I oil shales in the upper Green River Formation correlate well with low-maturity aromatic-asphaltic samples. We determined kinetic parameters for the source rocks and used them to develop basin models for hydrocarbon generation. The models show that hydrous pyrolysis kinetic parameters are more consistent with the natural data in terms of predicted timing and extent of oil generation as compared to models using Rock-Eval kinetics. (Begin page 1334)

Stratigraphic controls on vertical fracture patterns in Silurian dolomite, northeastern Wisconsin

Abstract: Vertical opening-mode fractures are mapped on quarry walls to assess the stratigraphic controls on fracture patterns in the relatively undeformed Silurian dolomite of northeastern Wisconsin. Our two-stage study uses maps of vertical fractures to assess the effectiveness of various types of stratigraphic horizons (e.g., organic partings or cycle-bounding mud horizons) in terminating opening-mode fractures. First, the mechanical stratigraphy of the exposures is interpreted from the observed fracture pattern. Both visual inspection and a newly developed quantitative method are employed to identify effective mechanical interfaces. The two methods show similar results, confirming the validity of qualitative visual inspection. The second stage of our study stochastically predicts mechanical stratigraphy and subsequent fracture pattern from empirical relationships between the observed sedimentary stratigraphy and the interpreted mechanical stratigraphy. For example, 63% of cycle-bounding mud horizons within the inner-middle and middle shelf facies associations serve as mechanical interfaces. These empirical percentages are input to a Monte Carlo analysis of 50 stochastic realizations of mechanical stratigraphy. Comparisons of the stochastically predicted and interpreted mechanical stratigraphy yield errors ranging from 13 to 33%. This method yields far better results than assuming that all stratigraphic horizons act as mechanical interfaces. The methodology presented in this article demonstrates an improved prediction of fracture pattern within relatively undeformed strata from both complete characterization of sedimentary stratigraphy and understanding mechanical controls on fracturing.

Using calibrated shale gouge ratio to estimate hydrocarbon column heights

Abstract: Fault-zone composition, estimated using the shale gouge ratio (SGR) algorithm, can be empirically calibrated with pressure data to define depth-dependent seal-failure envelopes relating SGR to fault-zone capillary entry pressure (FZP) by the equation: FZP (bar) = 10 (SGR/27 − C). C is 0.5 for burial depths less then 3.0 km (9850 ft), C is 0.25 for burial depths between 3.0 and 3.5 km (9850–11,500 ft), and C is 0 where the burial depth exceeds 3.5 km (11,500 ft).The seal-failure envelope provides a method to estimate the maximum height of a hydrocarbon column that can be supported by the fault. Leakage of hydrocarbons across a fault occurs when the buoyancy pressure exceeds the capillary entry pressure of the fault and is not confined to the crest of the structure or even to where the SGR value is lowest.Established calibration diagrams based on across-fault pressure differences have overgeneralized the relationship between increasing SGR and increasing pressure support. Calibration diagrams based on buoyancy pressure show that gas and oil data exhibit a correlation between increasing SGR and increasing buoyancy pressure but only between SGR values of 20 and 40%. No increase in the strength of a seal is present, as reflected by an increase in maximum supportable buoyancy pressure, at SGR values greater than about 40% for both gas and oil data. Column heights do not continue to increase in the SGR range 50–100%.Estimating hydrocarbon column heights using seal attributes depends upon the geologic input to the model, in particular, pressure data, volumetric shale fraction, and the precision of the three-dimensional mapping of reservoir geometry in the vicinity of the fault.

Architecture of an active mud-rich turbidite system: The Zaire Fan (Congo–Angola margin southeast Atlantic)Results from ZaïAngo 1 and 2 cruises

Abstract: Multichannel seismic data newly acquired during two ZaAngo surveys now provide an almost complete view of the Quaternary architecture of the Zaire Fan. Extending laterally from the southern Gabon margin to the Angola margin and longitudinally more than 800 km, the overall fan consists of three main individual fans that were deposited successively as overlapping depocenters. The individual fans are composed of channel/levee systems exhibiting similar seismic facies, external configurations, and organization to those described in other large mud-rich systems (e.g., the Amazon Fan). In particular, high-amplitude reflection units with a high oil-reservoir potential are recognized almost systematically as a basal sole for channel/levee systems. They possibly include true high-amplitude reflection packets related to avulsion processes below the avulsion points and coarse-grained basal levees related to the initial stages of levee aggradation subsequent to the avulsion. Correlations with Ocean Drilling Program Leg 175 Site 1077 indicate that the studied part of the Zaire Fan began to build in the late Pleistocene (780 ka). During the upper Quaternary, a great number of channel/levee systems (more than 80) were developed, possibly explained either by its permanent activity even during high sea level conditions or by the low Zaire River inputs. The frequent occurrence of channel entrenchment of either old or recent channels is another characteristic specific to the fan. Overdeepening of channels is probably partly caused by regressive erosion inside the parent channel in response to an avulsion and also in part because of other causes that are not fully understood.

How burial diagenesis of chalk sediments controls sonic velocity and porosity

Abstract: Based on P-wave velocity and density data, a new elastic model for chalk sediments is established. The model allows the construction of a series of isoframe (IF) curves, each representing a constant part of the mineral phase contributing to the solid frame.The IF curves can be related to the progress of burial diagenesis of chalk, which is revised as follows:Newly deposited carbonate ooze and mixed sediments range in porosity from 60 to 80%, depending on the prevalence of hollow microfossils. Despite the high porosity, these sediments are not in suspension, as reflected in IFs of 0.1 or higher.Upon burial, the sediments lose porosity by mechanical compaction, and concurrently, the calcite particles recrystallize into progressively more equant shapes. High compaction rates may keep the particles in relative motion, whereas low compaction rates allow the formation of contact cement, whereby IF increases and chalk forms. Rock mechanical tests show that when compaction requires more than in-situ stress, porosity reduction is arrested.During subsequent burial, crystals and pores grow in size as a consequence of the continuing recrystallization. The lack of porosity loss during this process testifies to the absence of chemical compaction by calcite-calcite pressure dissolution, as well as to the porosity-preserving effect of contact cementation.At sufficient burial stress, the presence of stylolites indicates that pressure dissolution takes place between calcite and silicates, and depending on pore-water chemistry and temperature, pore-filling cementation may occur over a relatively short depth interval. Limestone and mixed sedimentary rock form, and porosity may be reduced to less than 20%. Isoframe increases to more than 0.6.In hydrocarbon reservoirs in North Sea chalk, relatively high porosity and high IFs are found. The reason may be that recrystallization and porosity-preserving contact cementation progress, whereas pore-filling cementation is small, probably because pressure dissolution along stylolites is arrested. Pressure dissolution may be arrested for two reasons: (1) the introduction of hydrocarbons causes a fall in effective burial stress, and (2) adsorption of polar hydrocarbons on the silicates may shield calcite from the silicates.

A fuzzy logic approach for the estimation of facies from wire-line logs

Abstract: A method based on fuzzy logic inference can be used to identify lithological and depositional facies from wire-line logs. Fuzzy logic is inherently well suited to characterizing vague and imperfectly defined knowledge, a situation encountered in most geological data. It can thus yield models that are simpler and more robust than those based on crisp logic. The method is simple, easy to comprehend, and robust. It also generates several confidence measures that can be used to assess the quality of the analysis. Several enhancements, including static and dynamic constraints, are discussed. The technique is tested here by applying it to predict the depositional facies of a cored well in a marine carbonate environment and comparing the output with the facies derived from core analysis. The two show considerable agreement, which indicates that this method can be an effective means of predicting the facies of uncored wells from their logs. The method has advantages when contrasted with other techniques that rely on multivariate statistics and neural networks. Compared to those techniques, this method is simpler, easier to retrain, more reproducible, noniterative, and more computer efficient.

An integrated, quantitative approach to assessing fault-seal risk

Abstract: Fault sealing is one of the key factors controlling hydrocarbon accumulations and trap volumetrics and can be a significant influence on reservoir performance during production. Fault seal is, therefore, a major exploration and production uncertainty. We introduce a systematic framework in which the geologic risk of faults trapping hydrocarbons may be assessed.A fault may seal if deformation processes have created a membrane seal, or if it juxtaposes sealing rocks against reservoir rocks, and the fault has not been reactivated subsequent to hydrocarbons charging the trap. It follows from this statement that the integrated probability of fault seal can be expressed as {1 − [(1 − a)(1 − b)]} (1 − c), where a, b, and c are the probabilities of deformation process sealing, juxtaposition sealing, and of the fault being reactivated subsequent to charge, respectively. This relationship provides an assessment of fault-seal risk that integrates results from the critical parameters of fault-seal analysis that can be incorporated into standard exploration procedures for estimating the probability for geologic success. The integrated probability of fault seal for each prospect can be visualized using the fault-seal risk web, which allows rapid comparison of success and failure cases through construction of prospect risk web profiles.The impact of uncertainty (U) and the value of information (VOI) for each aspect of fault sealing on the overall fault-seal risk may be determined via the construction of data webs and the relation U = [1 − {(nw) / n}] 100, where nw is the value given to each data web parameter and n is the number of data web components. For example, the data web components required to assess fault reactivation risk are the orientation and magnitude of the in-situ principal stresses, pore pressure, fault architecture, and the geomechanical properties of the fault.Risking of the Apollo prospect, Dampier subbasin, North West shelf, Australia is presented as a worked example. Fault-seal risking for the Apollo prospect has been conducted on 10- and 100-ft oil columns to allow integration with volumetric probabilistic statements. The critical parameter for fault-seal risking at the Apollo prospect is the ability of disaggregation zone faults (low shale gouge ratio fault gouge) to support increasingly large hydrocarbon columns. Evaluation of the individual components for Apollo fault sealing indicates a = 0.3 (10-ft column) and a = 0.1 (100-ft column), b = 0.2, and c = 0.1. The overall probability of the Apollo trap-bounding fault sealing a 10-ft oil column is 0.4 or 40% (seal condition moderately unlikely). The likelihood that the fault seals oil columns greater than 100 ft is 0.3 (seal condition unlikely). Data web error margins for the Apollo prospect are 20% (juxtaposition uncertainty), 26% (fault-rock process uncertainty), and 27% (fault reactivation uncertainty). Recalculating each parameter by its uncertainty, for a 10-ft oil column, the upper value of integrated fault-seal risk is 0.5 (seal condition intermediate), and the lower value is 0.3 (seal condition unlikely). The upper value of integrated fault-seal risk for a 100-ft oil column is 0.3 (seal condition unlikely), and the lower value is 0.2 (seal condition very unlikely). The variation in the Apollo final risk calculation reflects the lack of prospect-specific data. The greatest VOI benefit for Apollo fault-seal prospectivity is sedimentary architecture data.

Salt structures and hydrocarbons in the Pricaspian basin

Abstract: Pricaspian basin geology is reviewed in the light of 500,000 km of seismic profiles and several thousand wells. We focus on how hydrocarbons from three sources accumulated in relation to the 1800 salt structures in a basin that changed little in planform from the Devonian to the Paleogene. Riphean to Carboniferous shelf sedimentary strata are still flat lying between a poorly known crystalline basement and a base of salt now 10 km deep. Slow and almost continuous sedimentation in the basin center downbuilt huge massifs in Permian salt initially 4.5 km thick. Basin sediments are flat lying or backtilted between down-to-basin growth faults along northern and western margins starved of sediments. By contrast, progradation of Permian sediments from the Urals, Triassic sediments from the South Emba shear zone, and Jurassic sediments from the Dombass-Tuarkyr fold belt downbuilt successive waves of salt structures basinward from margins in the east, southeast and then the south. A zone of salt overhangs records extrusion that starved basin-marginal salt structures, particularly during a basinwide hiatus in the Early Jurassic. Salt diapirs along polygonal normal faults rooting to the crests of still-potent salt structures through Cretaceous–Paleogene strata indicate that salt upbuilt back to the surface and resumed downbuilding. Coarse clastic fans infill deep canyons incised across the basin by rivers draining to the Caspian in Pliocene times.

Improving curvature analyses of deformed horizons using scale-dependent filtering techniques

Abstract: Fractures, which are common structural heterogeneities in geological folds and domes, impact the charge, seal, and trapping potential of hydrocarbon reservoirs. Because of their effects on reservoir quality, the numerical prediction of fractures has recently been the focus of petroleum geoscientists. A horizon's curvature is commonly used to infer the state of deformation in those strata. It is assumed that areas of elevated calculated curvatures underwent elevated deformation, resulting in a concentration of fractures and faults there. Usually, curvatures are calculated from spatial data after sampling the continuous horizon at discrete points. This sampled geometry of the horizon includes surface undulations of all scales, which are then also included in the calculated curvatures. Including surface undulations of all scales in the curvature analysis leads to noisy and questionable results. We argue that the source data must be filtered prior to curvature analysis to separate different spatial scales of surface undulations, such as broad structures, faults, and sedimentary features. Only those surface undulations that scale with the problem under consideration should then be used in a curvature analysis. For the scale-dependent decomposition of spatial data, we test the suitability of four numerical techniques (Fourier [spectral] analysis, wavelet transform filtering, singular value decomposition, factorial kriging) on a seismically mapped horizon in the North Sea. For surfaces sampled over a regular grid (e.g., seismic data), Fourier (spectral) analysis extracts meaningful curvatures on the scale of broad horizon features, such as structural domes and basins.

3-D seismic geomorphology: Insights into fluvial reservoir deposition and performance, Widuri field, Java Sea

Abstract: Three-dimensional seismic geomorphology provides an indication of a reservoir's internal and external architecture. This furthers an understanding of depositional processes and allows a prediction of fluid flow during hydrocarbon production. Seismic images of four fluvial reservoirs from Widuri oil field show a range of features related to point-bar accretion and stacking pattern. Lateral variations in reservoir quality and thickness follow scroll-bar patterns associated with lateral migration of a moderate- to high-sinuosity meandering river. These variations control fluid flow during primary and secondary hydrocarbon recovery. Interpreted bar and abandoned channel dimensions, compared with meander map form and wavelength, are consistent with observations of modern-day examples, which provides confidence in the depositional model. The high seismic resolution of the Widuri reservoirs provides useful analogs for other subsurface reservoirs from similar depositional environments.

Paleoenvironments and paleogeography of the Lower and lower Middle Jurassic coal measures in the Turpan-Hami oil-prone coal basin, northwestern China

Abstract: Detailed facies and paleogeographical analyses of extensive borehole and outcrop data from Lower and lower Middle Jurassic oil-prone coal-bearing sequences in the Turpan-Hami oil-producing basin of northwest China have led to the reconstruction of a basinwide depositional model. A total of 20 distinct lithofacies have been identified and grouped into braided fluvial plain, meandering fluvial plain, braided delta, meandering channel delta, and lacustrine depositional systems. Coal-forming swamps occur in each depositional system, but the preferred sites of accumulation are interdelta bay and lower delta-plain environments in the braided delta and meandering channel depositional systems, and it is in these sites that major oil-prone source rocks are located. A series of age-specific, basinwide, paleogeographical maps have been constructed leading to a depositional model for the basin. Results indicate that the basin experienced cyclic flooding to produce swamps and lakes, and that these characterize the deposition of the Lower and lower Middle Jurassic coal measures. Analyses indicate that both the Bogda and Harlik Mountains were uplifted prior to the Early Jurassic, and a lake separated the two mountain regions during the Early and early Middle Jurassic. From these results, it is interpreted that major oil-prone coal sequences are to be found in the western part of the Taibei depression of the basin, and thus, the full economic potential of the basin has yet to be fully realized.

Reservoir characterization of a Permian deep-water sandstone, East Ford field, Delaware basin, Texas

Abstract: Deep-water sandstones of the Delaware Mountain Group in west Texas and southeast New Mexico contained an estimated 1.8 billion bbl of original oil in place, but primary recovery from these fields is commonly less than 20%. East Ford field in Reeves County, Texas, which produces from the Ramsey sandstone in the upper Bell Canyon Formation, went directly from primary production to tertiary recovery by CO2 flooding. Field production has increased from 30 to more than 185 BOPD. Oil recovery has been improved by the CO2 flood, but not as much as expected. Geologic heterogeneities such as interbedded siltstones are apparently influencing reservoir displacement operations in the East Ford unit.A depositional model of the East Ford unit was developed using data from Bell Canyon outcrops and subsurface data. The Ramsey sandstones were deposited by turbidity currents in a basin-floor setting. The sandstones are interpreted as having been deposited in a channel-levee system that terminated in broad lobes; overbank splays filled topographically low interchannel areas. Injection wells located in splay sandstones apparently have poor communication with wells in channel sandstones, perhaps because communication is restricted through levee and channel-margin deposits. The south part of the unit is responding well to the flood because the injection and production wells are in the same interconnected lobe depositional environment.

Seismic frequency control on carbonate seismic stratigraphy: A case study of the Kingdom Abo sequence, west Texas

Abstract: Conceptual models and real three-dimensional (3-D) seismic data show that in progradational carbonate platform margin and slope deposits of the Kingdom Abo reservoir of the Permian basin, west Texas, primary seismic reflection events do not necessarily follow clinoformal geologic-time surfaces. The seismic frequency content of the data controls the dip and architecture of seismic reflection events. High-frequency seismic data tend to follow thinner, time-bounded clinoform depositional elements (time-stratigraphic units), whereas low-frequency seismic data tend to image thicker, low-angle lithofacies units (time-transgressive units). In seismic data of moderate frequency, both clinoform units and flat lithofacies units are imaged, creating complex interference patterns that are difficult to interpret.Experiments with models and real data demonstrate that seismic data can be selectively filtered in the signal bandwidth to help distinguish time-stratigraphic units from lithostratigraphic units. Selective filtering alters the dominant frequency of the data to match a desired scale of geologic objects. If there are enough high-frequency components in the seismic data, true clinoform stratigraphy can be imaged even if the data are dominated by lower frequency components.Seismic modeling of outcrop of the Abo sequence in Apache Canyon, Sierra Diablo, west Texas, indicates that a dominant frequency of 100 Hz is needed to recover true clinoform stratigraphy using seismic data. The interpretation of available 3-D seismic data can only partially distinguish time-stratigraphy from lithostratigraphy because of the lack of frequency components greater than 70 Hz in the data. Application of this outcrop model in seismic modeling avoids interpretational pitfalls that can occur if the dominant frequency of the seismic data is not matched to the unit thicknesses that need to be resolved.

Overpressuring mechanisms in the Yinggehai Basin, South China Sea

Abstract: Yinggehai Basin is an elongate Cenozoic rift basin on the northwestern margin of the South China Sea continental shelf. Its thick (17 km) basin fill is characterized by high geothermal gradient and high overpressure. Overpressure associated with nonequilibrium compaction mainly occurs at depths more than 2800 m at the basin center and more than 4000 m at the basin margin because the shallow-buried Neogene and Quaternary strata lack effective seals. This regional overpressure distribution, however, is disrupted at basin center where high overpressure occurs in permeable formations at a depth as shallow as 1400 m on top of a series of deep-seated faults and fractures. We studied the processes and mechanisms of overpressuring via numerical modeling that couples basin filling, sediment compaction, and thermal and pressure fields to approach the origin of the shallow high overpressure. Model results indicated that an increase of fluid volume due to natural-gas generation by organic cracking is not large enough to generate the overpressure because of the limited amount of organic matter. The shallow overpressure has probably been generated allogenically. Deep open faults have served as vertical hydraulic conduits and channeled the deep high pressure into shallow permeable formations.

Progradation along a deeply submerged Oligocene–Miocene heterozoan carbonate shelf: How sensitive are clinoforms to sea level variations?

Abstract: We combine two- and three-dimensional seismic stratigraphic interpretation with paleobathymetric analysis from benthic foraminifera to understand the genetic significance of prominent seismic discontinuity surfaces typically mapped as sequence boundaries and flooding surfaces in the late Paleogene–early Neogene northern Carnarvon Basin.The progradational succession, dominated by heterozoan carbonate sediments, is divided into 5 northwest-prograding clinoformal sequences and 19 subsequences. Clinoform fronts progress from smooth to highly dissected, with intense gullying apparent only after the middle Miocene optimum. Once initiated, gullies become the focus for sediment distribution across the front. Bottomsets remain relatively sediment starved without the development of aprons on the lower slope and basin. Small-scale variability suggests heterogeneous sediment dispersal through the slope conduits. Along-strike sediment transport superimposed on progradation changes from southwest directed in the late Oligocene to northeast directed in the late middle Miocene, suggesting a major reorganization of circulation in the southeastern Indian Ocean.Prominent seismic discontinuity surfaces represent both intervals of shallow paleowater depth and flooding of the shelf. Partial exposure of the shelf indicated by karst morphology is coeval, with middle to outer neritic paleowater depths on the outer shelf. Instead of building to sea level, progradation occurs with shelf paleowater depths at the clinoform rollover greater than 100 m. Therefore, in the northern Carnarvon Basin, onlap onto the clinoform front is not coastal, and the sensitivity of the clinoforms to sea level changes is muted.

Possible controls of hydrogeological and stress regimes on the producibility of coalbed methane in Upper Cretaceous–Tertiary strata of the Alberta basin, Canada

Abstract: The coalbed methane potential and producibility of any coal-bearing strata are strongly affected by the hydrogeological regime of formation waters and by coal permeability, which in turn depends on the effective stress regime of the coals. Peat that accumulated in the Alberta basin during the Late Cretaceous and early Tertiary led to the formation of coal deposits that may contain significant coalbed methane resources. The flow of formation waters plays an important role in the maintenance and producibility of this resource. The present-day flow is driven by gravity (topography) and erosional rebound and is controlled by rock permeability and the presence of gas-saturated sandstones. The estimated gas in place in the Tertiary–Upper Cretaceous coals decreases significantly with stratigraphic age, ranging between less than 2 bcf/mi2 in the lower coal zones and 12 bcf/mi2 in the uppermost coals. The gas content, especially of the deeper coals, is lower than would be expected for the corresponding coal rank and burial depth, most likely because the underpressuring has caused the release of gas from the coals and accumulation in adjacent sands. The shallow coals, although of low rank, may contain important amounts of late-stage biogenic methane. The salinity of formation water in shallow coal seams, where the flow is driven by topography, is low, generally less than 1500 mg/L, although in places, it reaches 3000–5000 mg/L. The salinity of formation water in the deeper, underpressured strata in the west-central part of the basin is significantly higher, reaching 18,000 mg/L. This affects treatment and/or disposal strategies with regard to the water produced concurrent to coalbed methane.The producibility of this resource depends on coal permeability, which decreases west-southwestward with increasing burial depth, from the order of several darcys in the shallow zones to millidarcys in the deep zones. The minimum effective stress, which affects coal permeability by closing fractures, increases west-southwestward from zero at the erosional edge of these strata to approximately 20 MPa near the Rocky Mountain deformation front. Fractures, including those in coal seams, will generally be vertical and will propagate on a southwest-northeast axis along the direction of the maximum horizontal stress, in a direction generally perpendicular to the Rocky Mountain deformation front.Considering the hydrogeological and stress regimes in conjunction with estimations of the gas content in coals, the region with probably good coalbed methane potential and producibility are the Ardley coal zone in the Scollard Formation and maybe, to a lesser extent, the coal zones of the stratigraphically deeper Edmonton and Belly River groups along their respective subcrop in central and southern Alberta. The deep Edmonton and Belly River strata in western and central Alberta have most likely a reduced coalbed methane potential as a result of lower gas content and of low permeability. These regional considerations need to be applied against local studies of coal thickness, rank, permeability, and gas content to identify the best targets for coalbed methane exploration and production.

Late Paleozoic depositional history of the Tarim basin, northwest China: An integration of biostratigraphic and lithostratigraphic constraints

Abstract: This study provides the first detailed lithostratigraphic and biostratigraphic constraints for improving stratigraphic resolution for hydrocarbon prospecting and exploration in the Tarim basin. A total of 49 stratigraphic units (38 formations and 11 members), ranging in age from the latest Devonian to Permian, are reviewed or redefined in terms of nomenclatures, lithology, age constraints, and lateral distributions based on the detailed field works or newly published data. Of these, the Piqiang Formation (new formation) is proposed to include the reefal carbonates of Asselian–Sakmarian age from the northern Tarim. The subsurface upper Paleozoic stratigraphic framework of the desert areas of the basin is also established for the first time. The high-resolution, basinwide stratigraphic correlations reveal that the sedimentation of the basin in the late Paleozoic was extremely uneven. Of these, the Famennian to Changhsingian successions are completely recorded in the southwestern margin areas of the basin. Here, five eustatic sedimentary cycles are well recognizable, suggesting the sedimentation was more eustatically controlled and little affected by local tectonism. The late Paleozoic successions of both Kalpin and Taklimakan regions are commonly interrupted by major hiatuses at various horizons, suggesting that the sedimentation was apparently modified by local tectonism. Of these, the northward movement of the Tarim block and its subsequent collision with the Yili microcontinent (part of the Kazakhstan plate) may be principally accountable for the discrepancy in the sedimentation of the various regions in the basin in the late Paleozoic.

Clay smear seals and fault sealing potential of an exhumed growth fault, Rio Grande rift, New Mexico

Abstract: The Calabacillas fault, New Mexico, is an exhumed growth fault that provides insights on the processes of clay smear formation and the effectiveness of fault seal prediction for faults of this type in the subsurface Exposed clay smears range from being continuous and having a taper geometry to being semicontinuous and segmented by secondary faults In some cases, source beds are truncated at the fault and there as no attached clay smear Detailed mapping of the fault zone shows that there is a veneer of clay gouge on the fault that is interrupted by multiple gaps that would reduce the ability of the fault to be an effective seal over geologic timescales The presence of releasing dip relays in footwall source beds and the evolution of the dip relay during the growth of the fault zone primarily control the variability in clay smear type and continuity Source bed plasticity, composition, and thickness play a secondary role As the fault zone grows, the dip relay is breached, and the clay smear is progressively segmented by normal faults that translate it down the fault and eventually truncate it from its source Smearing-type algorithms (CSP, for example) overpredict the likelihood of fault seal at the base of the source bed, because the clay smear is commonly detached from its source A key threshold for fault seal prediction is the stage of fault growth at which the clay smear tapers become separated from their source beds Below this threshold, smear-type algorithms work best Above this threshold, abrasion-type algorithms work best

Origin of minerals in joint and cleat systems of the Pottsville Formation, Black Warrior basin, Alabama: Implications for coalbed methane generation and production

Abstract: Coalbed methane is produced from naturally fractured strata in the lower Pennsylvanian Pottsville Formation in the eastern part of the Black Warrior basin, Alabama. Major fracture systems include orthogonal fractures, which consist of systematic joints in siliciclastic strata and face cleats in coal that strike northeast throughout the basin. Calcite and minor amounts of pyrite commonly fill joints in sandstone and shale and, less commonly, cleats in coal. Joint-fill calcite postdates most pyrite and is a weakly ferroan, coarse-crystalline variety that formed during a period of uplift and erosion late in the burial history. Pyrite forms fine to coarse euhedral crystals that line joint walls or are complexly intergrown with calcite.Stable-isotope data reveal large variations in the carbon isotope composition of joint- and cleat-fill calcite (10.3 to +24.3 Peedee belemnite [PDB]) but only a relatively narrow range in the oxygen-isotope composition of this calcite (16.2 to 4.1 PDB). Negative carbon values can be attributed to 13C-depleted CO2 derived from the oxidation of organic matter, and moderately to highly positive carbon values can be attributed to bacterial methanogenesis. Assuming crystallization temperatures of 2050C, most joint- and cleat-fill calcite precipitated from fluids with 18O ratios ranging from about 11 to +2 standard mean ocean water (SMOW). Uplift and unroofing since the Mesozoic led to meteoric recharge of Pottsville strata and development of freshwater plumes that were fed by meteoric recharge along the structurally upturned, southeastern margin of the basin. Influxes of fresh water into the basin via faults and coalbeds facilitated late-stage bacterial methanogenesis, which accounts for the high gas content in coal and the carbonate cementation of joints and cleats.Diagenetic and epigenetic minerals can affect the transmissivity and storage capacity of joints and cleats, and they appear to contribute significantly to interwell heterogeneity in the Pottsville Formation. In highly productive coalbed methane fields, joint- and cleat-fill calcite have strongly positive 13C values, whereas calcite fill has lower 13C values in fields that are shut in or abandoned. Petrographic analysis and stable-isotope geochemistry of joint- and cleat-fill cements provide insight into coalbed methane reservoir quality and the nature and extent of reservoir compartmentalization, which are important factors governing methane production.

Regional sequence stratigraphic setting and reservoir geology of Morrow incised-valley sandstones (lower Pennsylvanian), eastern Colorado and western Kansas

Abstract: Oil and gas exploration for the lower Pennsylvanian Morrow Formation of eastern Colorado, western Kansas, and northwestern Oklahoma provides a subsurface data set that transects the entire range of lowstand depositional systems from incised-valley-fill systems to deep-water basin-floor systems in one composite depositional sequence. One compound incised-valley fill that is a part of this system contains three facies tracts with unique reservoir characteristics: (1) the updip facies tract is dominated by amalgamated fluvial channel sandstones, (2) the transition facies tract consists of fluvial channel sandstones interbedded with finer grained estuarine sandstones, and (3) the downdip facies tract consists of ribbonlike fluvial channel sandstones isolated in estuarine shale.A 175-mi-long (283-km-long) longitudinal cross section through one trunk of the incised-valley-fill drainage shows that internal valley-fill strata change significantly as a function of the interplay of varying depositional systems down gradient in the valley. Key contrasts in reservoir performance are documented as a function of changes in reservoir characteristics, trap controls, and trap configurations from updip to downdip in this valley-fill drainage.The strata of the Morrow Formation were deposited in a cratonic basin during a period in the Earth's history when the climate was cooler than today. High-frequency changes of sea level across an extremely low-gradient depositional surface controlled erosion and deposition. These facies tracts reflect the response of valley-fill sedimentary processes to high-frequency relative sea level changes resulting from glacio-eustasy. The resultant valley-fill systems have many characteristics in common with published valley-fill models, but have significant differences as well.

Stratigraphy, microfacies, and petroleum potential of the Mauddud Formation (Albian–Cenomanian) in the Arabian Gulf basin

Abstract: The Albian–Cenomanian Mauddud Formation extends over most parts of the Arabian basin including north Iraq. The formation consists mainly of Orbitolina-bearing limestone with local basin margin rudist buildups in the offshore North field of Qatar and northeast Iraq. Extensive dolomitization, with wide variations in both extent and texture, has been reported from both outcrops and wells. The Jurassic–Cretaceous pelagic strata are probably the possible source for the Mauddud Formation oil in northern Iraq, whereas indigenous sources in the Mauddud strata and Nahr Umr shales, as well as the Upper Jurassic rocks, are probably the source rocks in the southern parts in the basin. Porosity of 10–35% and permeability of 10–110 md have been reported from different fields of the basin. This porosity is attributed to a combination of dolomitization, fracturing, and dissolution. There are two main oil provinces where the Mauddud Formation is a major oil-producing reservoir. The northern province includes Iraq's oil fields such as Ain Zalah, Bai Hassan, and Jambur. The southern province includes the Ratawi field in southern Iraq, Raudhatain, Sabriya, and Bahra fields in Kuwait, Bahrain (Awali) field in Bahrain, and Fahud and Natih fields in Oman. The formation has high oil potential in the southern and southeastern fields of Iraq and the offshore areas of Qatar and Saudi Arabia.