Reservoir Facies Research Articles

Seismic attributes and acoustic impedance inversion in interpretation of complex hydrocarbon reservoirs

Seismic attributes along with seismic inversion are used to study a challenging reservoir facies from Boonsville field in north central Texas. Two thin reservoirs, Upper Caddo and Lower Caddo, separated by a nonproductive thin limestone formation are investigated. Seismic was not an unambiguous indicator of the Caddo reservoir. The Caddo event exhibits doublet character reflections when productive facies are present. However, this character proved to be a false diagnostic of the Caddo reservoir. Wells drilled on interpreted doublet reflections turned out to dry holes penetrating two thin limestone units instead.First, some modern poststack processing techniques are used to remove incoherent noise and improve the data resolution and interpretability. Seismic instantaneous attributes (i.e., amplitude, phase, and frequency) are then calculated to infer seismic expressions of the reservoir and the limestone formations. Next, spectral decomposition is performed to study the frequency responses of the different lithotypes. Interestingly, the attribute images and frequency maps could distinguish between the different investigated units. However, some limestone units show up similar to the Lower Caddo formation in the frequency images. Model-based acoustic impedance inversion is carried out on seismic lines spanning both zones. Acoustic impedance sections reveal that producing wells and dry wells penetrate different formations. The cosine of instantaneous phase attribute along with impedance sections supports the above interpretations and displays more clearly where the Caddo reservoir is traversed and where it is not. This study demonstrates that integration of modern poststack processing and novel seismic attributes can lead to extract more key information about challenging reservoirs with less ambiguity.

Petrophysical Characterization of Bioturbated Sandstone Reservoir Facies In the Upper Jurassic Ula Formation, Norwegian North Sea, Europe

Abstract A petrophysical study of bioturbated shoreface sandstone rocks was completed by mapping local variations in air permeability measured in core samples acquired from the Upper Jurassic Ula Formation of the Norwegian Central Graben. Analysis of the shoreface fabrics resulting from bioturbation was studied using arithmetic, harmonic, and geometric numerical modeling and analytical techniques. The arithmetic mean best illustrates samples dominated by high volumes of horizontal or subvertical burrows (50–80%). The distal Skolithos to proximal Cruziana ichnofacies is an example of a rock fabric that can be characterized using the arithmetic mean. The harmonic mean best exemplifies samples dominated by low volumes of vertically oriented burrows (10–50%). The archetypal Skolithos ichnofacies is an example of a rock fabric that can be characterized using the harmonic mean. At extreme volumes of bioturbation (90–100%), isotropic flow units begin developing irrespective of burrow orientation. Numerical models of Ophiomorpha in two different sedimentary bedding features (laminated sandstone and massive sandstone) show that single-phase fluid flow is influenced by parameters such as burrow permeability, burrow connectivity, and bioturbation volume. Spot-permeametry measurements show that the Ophiomorpha burrows have higher permeability values than the host matrix. In the laminated-sandstone models, horizontal shale laminae and low bioturbation intensities promote lamination-parallel fluid flow. At higher volumes of bioturbation, fluid flow becomes increasingly isotropic due to greater amounts of burrow interpenetrations across mud laminae. In the massive-sandstone model, no flow barriers exist. As such, low volumes of bioturbation result in only minor influences on fluid flow. At higher volumes of bioturbation, greater burrow interconnectivity occurs and results in an enhancement of vertical and horizontal burrow permeabilities. Based on the results outlined above, this paper emphasizes the impact bioturbation plays in helping improve reservoir quality in the Ula Formation. Perhaps more importantly, the effectiveness of the numerical models presented to characterize fluid flow in different bioturbated fabrics (e.g., archetypal Skolithos ichnofacies) highlights the fact that the fluid-flow results outlined in this paper can also be applied more broadly to different shoreface successions using ichnofacies knowledge alone.

四川盆地中二叠统层序地层格架下岩相古地理特征

随着对四川盆地碳酸盐岩储层的重视和大力勘探，中二叠统发育的滩相储层也构成了盆内有利的含气层位之一。本文根据岩心观察、野外剖面实测、镜下岩石薄片鉴定分析和其它测试资料，结合岩石学、古生物、沉积构造等沉积相标志的综合研究，认为研究区中二叠世主要发育浅水型碳酸盐岩台地沉积，细分为碳酸盐岩台地和台地前缘斜坡相及若干亚相和微相。以经典层序地层学理论为指导，通过以岩性–岩相转换界面为主的层序界面识别，确定中二叠统发育5个II型三级层序，每个层序划分出TST和HST两个沉积体系域。在沉积相和层序地层学分析的基础上，以各层序体系域作为编图单元和“单因素分析综合作图法”为技术方法，编制了各体系域的岩相古地理图并对其演化特征进行了分析。结合各相带储集物性特征，认为台缘滩和台内滩为最有利储集相带，尤以SQ2-HST和SQ4-HST沉积期形成的滩相颗粒灰岩经过白云石化作用改造后更具储集意义。 With the recognition and vigorous exploration of carbonate reservoirs in Sichuan Basin, bank facies reservoir developed in middle Permian Maokou and Qixia Formation also constitute beneficial layer of the basin where new gas source can be discovered. According to core observation, field profile measurement, microscopically rock thin section identification, and other testing data, combining the research of sedimentary facies signs such as petrology, paleontology, sedimentary structure, etc., the area develops sedimentary model as shallow-water carbonate platform in middle Permian, further classifies as the sedimentary facies of carbonate platform, platform margin slope and several subfacies and microfacies. We apply Vail’s classical sequence stratigraphy theory as guidance and identify stratigraphic sequence boundaries as lithology-lithofacies convert interface, so determine that Middle Permian develops five Ⅱ-type third degree sequence, and each sequence is divided into two depositional system tracts as TST and HST. Base on sedimentary facies and sequence stratigraphy analysis, we take each sequence systems tract as the mapping unit and the “single-factor analysis and comprehensive mapping method” as the technical methods and compose lithofacies paleogeography map of each sequence system tract and describe its evolution character. Associated with reservoir physical property character of each phase belt, the platform edge shoals and inner platform shoals that are considered the most beneficial reservoir facies, especially shoal facies grain limestone in SQ2 HST and SQ4 HST which was dolomitisated has more reservoir significance.

AVO-derived attributes to differentiate reservoir facies from non-reservoirs facies and fluid discrimination in Penobscot area, Nova Scotia

The discrimination of hydrocarbon (gas or oil) facies from non-hydrocarbon (wet sands) facies is an important goal in quantitative seismic interpretation and reservoir estimation. The differentiation of hydrocarbon facies from non-hydrocarbon in Mississauga Formation of early Cretaceous in Penobscot area is a difficult task due to smaller net pay thickness and shaly sand intervals. Based on seismic interpretation and wireline logs, five sand plays are identified in the middle of Mississauga Formation. Four sands have hydrocarbons while top of sand 5 represents hydrocarbon water transition zone. Among these four, the pay sand 4 is analyzed for hydrocarbon facies. Wireline logs and seismic data are used to derive various amplitude versus offset (AVO) based attributes such as: acoustic (I P ) and shear (I S ) impedances, Poisson ratio (σ) etc. Further, the combined attributes e.g., product of Lame parameters (μ, λ) with density (ρ), their ratio (λ/μ), difference between bulk modulus (K) and shear modulus (μ), Δμρ/μρ, Δ(λ/μ + 2)(λ/μ + 2) and the pore space modulus (K P ) are also analyzed to find out the best attribute as a hydrocarbon facies discriminator from non-hydrocarbon facies in the shale imbedded pay sand 4 of Mississauga Formation. First, petrophysical parameters such as P and S wave impedances, Lame’s parameters etc. are extracted from log data. Then, appropriate pairs of seismic attributes are crossplotted so that the hydrocarbon and non-hydrocarbon facies cluster together for quick identification and interpretation. Gamma ray index is crossplotted against spontaneous potential log to mark sand and shale facies. Fluid substitution modeling for various fluid types and saturation is also done which demonstrate that the cross-plots between different rock physics parameters can be used to distinguish between reservoir fluids. Our analysis reveals single P-wave based attributes are not sufficient to discriminate fluids thus the use of multi-attributes such as K P , λρ and K-μ is more effective to discriminate the hydrocarbon and non-hydrocarbon facies. The analysis of these cross-plots was done to map the reservoir sands and the hydrocarbon-water contact.

Seismic facies analysis from well logs based on supervised classification scheme with different machine learning techniques

Seismic facies analysis (SFA) has been proven to be useful in interpreting seismic data, allowing significant information about subsurface geological structures to be extracted. SFA uses different seismic attributes extracted from 3D seismic data and well logs to construct detailed seismic facies and lithology variation maps. Accurate seismic facies map could be used for reservoir exploration, optimization, management, and development. The recent SFA research was mainly based on unsupervised methods, with few works done using supervised classification. Therefore, this study focuses on supervised classification for qualitative mapping of the reservoir facies distribution. Precisely five well-known classifiers, called the multilayer perceptrons (MLPs), support vector classifier (SVC), Fisher, Parzen, and K-nearest neighbor (KNN). Each classifier was tested to provide an opportunity for the direct assessment of their feasibility in the classification of facies. The approach was applied on the carbonate reservoir from a real oil field in Iran. The numerical relative errors associated with different classifiers as a proxy for robustness of SFA provides reliable interpretations. Our results show stability of both SVC and MLP classifiers in supervised-classification-based studies although SVC has relatively better results.

The role of seismic attributes in understanding the hydraulically fracturable limits and reservoir performance in shale reservoirs: An example from the Eagle Ford Shale, south Texas

As the importance of self-sourcing reservoirs continues to increase, it is more important than ever to evaluate rock properties that contribute to productive wells. It has become increasingly evident that in order to maximize potential returns, an integrated approach to shale play characterization is necessary to identify productive areas. Numerous criteria exist to characterize ultra-low permeability shale reservoirs and their associated resource potential; these include measures of organic richness, thermal maturity, lithologic heterogeneity, and formation brittleness. The latter, a descriptor of the geomechanical rock properties, can play a significant role in overall well performance and is commonly a key productivity driver. Thus, an understanding of the mechanical properties of the target section is fundamental for high-grading prospective areas, well placement design, and hydraulic stimulation effectiveness. Observation of geomechanical attributes extracted from seismic data in the Eagle Ford Shale captures changing mechanical properties indicative of strike-oriented lithologic facies changes. Using acoustic logs, core, and three-dimensional seismic data, we assess the mechanical contrast between Eagle Ford facies units and their effect on well performance. We use three-dimensional seismic data to map the structure and facies distribution in an area where identification of reservoir facies is a major challenge to development drilling. In this study, we demonstrate how Young’s modulus and density, inverted from three-dimensional seismic data, prove as effective discriminators for the purpose of identifying and mapping facies changes and establishing the hydraulically fracturable limits in areas where effective stimulation and proppant embedment in the formation during pressure drawdown is a concern. The result is an interpretation that identifies and uses the mechanical changes from three-dimensional seismic data attributes associated with the brittle carbonate-rich Eagle Ford facies to predict both the reservoirs hydraulically fracturable limits as well as the variability in well performance associated with proppant embedment. The changes in mechanical properties of the Eagle Ford facies are important in high-grading productive intervals in these ultra-low permeability rocks. We believe we can apply this method to other shale reservoirs where rock mechanics may play an important role.

The Pretty Hill Formation as a natural analogue for CO2 storage: An investigation of mineralogical and isotopic changes associated with sandstones exposed to low, intermediate and high CO2 concentrations over geological time

The Pretty Hill Formation of the Otway Basin (Australia) has been studied as a natural analogue for geological storage of anthropogenic CO2 in order to examine the effects that CO2 concentration and reservoir heterogeneity have on CO2-related reactions. New petrographic data are presented, which validate the use of Hylogger™ as a tool to investigate high-resolution vertical changes in reservoir mineralogy. The integrated data set confirms earlier interpretations, showing that chlorite has been altered to kaolinite and siderite/ankerite in reservoir facies exposed to moderate and high CO2 concentrations, while chlorite remains the dominant clay mineral in all parts of the formation where CO2 content is low.Differences have been observed in the degree of CO2-related reaction relative to CO2 concentration and reservoir heterogeneity. Where CO2 content is very high (c. 98mol%) and associated with high water saturations, both chlorite and detrital feldspars have undergone complete reaction in the reservoir facies, resulting in quartzose sandstones with a kaolinite matrix, and with siderite as the dominant carbonate precipitate. Conversely, where CO2 content is moderate (c. 29–57mol%) and within the gas leg of the reservoir, chlorite has undergone significant reaction, but much of the original feldspar is preserved, suggesting relatively minor reaction. Carbonate cements from the moderate CO2 gas-leg comprise calcite, siderite and ankerite, occurring as cemented zones associated with rock heterogeneities and the present-day gas–water contact. Heterogeneities within the gas-leg are likely to have associated pore fluid contacts, whereby relatively high water saturations will be present in the fine-grained baffles and seals. The most advanced feldspar reaction occurs locally at the contact between baffles and reservoir rock, while reactions have been significantly impeded in the finer grained units due to their low permeabilities.Stable isotope data presented for carbonate cements analysed from wells with low and moderate CO2 levels show no clear distinction. Relatively early formed calcite has δ13C values that require an organic carbon source, suggesting precipitation unrelated to the reservoir CO2 in the Otway Basin. In contrast, diagenetically late calcite and siderite samples display two distinct δ13C groups (dependent on carbonate type), where the calculated fluid carbon isotope compositions are similar to documented magmatic CO2 reservoired in the nearby Caroline Field. This suggests that magma-derived CO2 may have been more prevalent through the Pretty Hill Formation than previously thought. Although the CO2 has not been contained over the long term in the low CO2 sites, it may have caused the local dissolution of carbonate and laumontite cement, and also contributed a source of carbon for late-stage calcite cements.These studies illustrate the importance of understanding both the reservoir composition and vertical heterogeneity of potential storage systems. Fluid–mineral reactions are likely to be advanced within stacked reservoir facies and impeded within siltstone layers, while the distribution of carbonate cement may increase the reservoir heterogeneity by the formation of cemented siltstone/sandstone layers, thereby creating impermeable barriers or baffles to CO2.

Depositional facies and platform architecture of microbialite-dominated carbonate reservoirs, Ediacaran–Cambrian Ara Group, Sultante of Om

Intrasalt carbonates of the Ediacaran–Cambrian Ara Group constitute a significant reservoir element of the intrasalt “stringer” play in Oman, in which dolomitic carbonates are encased in salt at depths of 3 to 7 km (1.9 to 4.3 mi). These reservoir carbonates have significant microbial influences. Although Ara Group reservoirs are mostly latest Precambrian, the models developed here may be applicable to younger microbially dominated carbonate reservoirs in basins of higher salinity when higher organisms are excluded, in lacustrine settings where calcified invertebrates are not a significant source of carbonate, or after periods of mass extinction before faunal recovery. A broad range of carbonate facies provides the context in which to understand the origin of the microbialite-dominated reservoirs developed across both ramp and rimmed shelf profiles. Major facies associations include carbonate-evaporite transition zone, deep ramp and slope, subtidal microbialites, clastic-textured carbonates, and restricted peritidal carbonates. Microbialites are subdivisible into a number of facies that all have significance in terms of understanding environmental history as well as reservoir properties, and that help in predicting the location of reservoir fairways. Microbially influenced facies include shallow subtidal thrombolites with massive clotted textures and very high initial porosities (>50%), shallow subtidal pustular laminites with cm-scale variability of lamina morphology, deeper subtidal crinkly laminites that show mm-scale variability of lamina morphology, and intertidal tufted laminates that show mm- to cm-scale tufted textures. Other reservoir facies are more conventional grainy carbonates including ripple cross-stratified grainstone–packstone, hummocky cross-stratified grainstone–packstone, flat pebble conglomerate, ooid and intraclast grainstone–packstone, and Cloudina grainstone–packstone. These facies are almost invariably dolomitized and all have moderate to excellent reservoir quality. These facies comprise carbonate platforms, broken up during salt tectonics, that range up to 160 m (525 ft) in thickness and extended laterally, prior to halokinesis, for tens to over 50 km (31 mi). The distribution of reservoir facies follows sequence stratigraphic predictions, with microbialites occurring in every accommodation profile. Late highstand and early transgressive systems tracts favor greater lateral extent of thrombolite build-ups, whereas later transgressive to early highstand system tracts favor greater lateral discontinuity and compartmentalization of buildup reservoir facies. Pustular laminites occur in close association with thrombolite buildups but form laterally extensive sheets in late transgressive to late highstand periods. Crinkly laminites form during late transgressive to early highstand systems tracts and may represent maximum flooding intervals when the flux of carbonate sediment was greatly reduced allowing pelagically derived organics to accumulate.

High-resolution sequence stratigraphy of the Upper Ordovician Montoya Group, southern New Mexico and western Texas: Outcrop analog of an unconventional chert and carbonate reservoir

The Upper Ordovician Montoya Group crops out in southern New Mexico and westernmost Texas and records predominantly subtidal deposition on a gently dipping carbonate ramp that was subsequently almost entirely dolomitized. The Montoya Group is a third-order composite sequence composed of six regionally correlative, shallowing-upward, third-order depositional sequences (M0–M5). Sequence M0 has sandstone at its base that is overlain by skeletal packstone-grainstone. Sequence M0 occurs only locally and was likely deposited in a topographic low formed during regional development of the unconformity following El Paso Group deposition. Sequence M1, marking the initial widespread transgression over the Ellenburger unconformity, consists of sandstone updip that passes downramp into skeletal packstone. The highstand systems tract (HST) of M1 consists of a prograding skeletal grainstone that was subaerially exposed upramp. Sequence M2, which contains the second-order maximum flooding surface, has abundant subtidal cherty carbonate at its base, which shallows upward into a widespread, prograding coral packstone-grainstone in the HST. Sequence M3 also contains abundant downramp chert that passes upramp into an aggrading crinoidal shoal and farther upramp into peritidal mudstone. Sequence M4 records an extensive basinward shift in facies as peritidal burrowed and cryptalgalaminated mudstone prograded over subtidal carbonate. Sequence M5 is only locally developed downramp and consists of crinoidal grainstone with abundant evidence of subaerial exposure. A regional unconformity separates the Montoya Group from the Silurian Fusselman Dolostone or younger units. Parasequences (meter-scale cycles) recording low- to moderate-amplitude relative sea level fluctuations are ubiquituous features at individual outcrops but are difficult to correlate regionally. The abundance of syn- or early depositional chert in the subtidal facies indicates that the Montoya Group was deposited within a region of strong regional upwelling along southern Laurentia. This early formed chert was the reservoir facies in a successful Upper Ordovician gas play in Ward and Reeves Counties, Texas.

Influence of variograms in 3D reservoir-modeling outcomes: An example

Three-dimensional reservoir models are used routinely for various purposes in the E&P business to support value-based decisions. One of the key challenges in 3D reservoir modeling is distributing the identified facies and their associated properties in the defined 3D structural/stratigraphic framework respecting geologic knowledge and available well data. Different geostatistical techniques are used for populating the reservoir facies and properties in the 3D reservoir models which have different working inputs and assumptions. Most reservoir-characterization studies use variogram-based geostatistical-modeling methods to accurately and efficiently represent reservoir heterogeneities. The variogram-based techniques constrain 3D reservoir models to local data which represent the geologic knowledge and help to create appropriate flow behaviors through dynamic simulation. However, simulation results obtained from those techniques are highly dependent on available data, selected variogram model, and the geomodeler's geostatistical knowledge and geologic experience. To illustrate the impact of variogram modeling on 3D reservoir-modeling outcomes, multiple 3D reservoir models were generated using different variograms for a siliciclastic reservoir. As expected, the results obtained from the models show significant variations, which indicate that selection of appropriate variogram models, which is critical for facies and property distribution in 3D static models, affects original hydrocarbon in place (OHIP) and recoverable resources/reserves estimation and production forecasts. A sensitivity analysis of the variogram parameters in the 3D static models and its impact in the dynamic simulation should be considered an integral part of the 3D modeling workflow.

Applying the cluster analysis technique in logfacies determination for Mishrif Formation, Amara oil field, South Eastern Iraq

Reservoir facies determination is the most important job in oil exploration which dominantly relies on the major properties of rocks. Fundamental properties of rocks are usually understood by their detailed description in the field (lithofacies analysis) and laboratory (petrofacies analysis). The facies (lithofacies and petrofacies) determination in most subsurface studies is impractical, due to lack of cores and cuttings. In such situations, where the wire line logs are the only data available, the logfacies or electrofacies are determined instead. In this study, the available logs (gamma ray, density, Neutron, and sonic logs) for four wells (Am-1, Am-4, Am-5, and Am-6) were used to divide Mishrif Formation into seven units separated by barrier beds. Using cluster analysis in this study practiced the logfacies determination in each unit of Mishrif Formation in Amara oil field using Interactive Petrophysics software. The types of input data into Interactive Petrophysics software to determine logfacies are gamma ray log, porosity, and water saturation which are used to create 15 clusters and determine six groups of logfacies. In this paper, the vertical variations of logfacies for Mishrif Formation are carried out based on six groups of logfacies. These groups of logfacies are classified based on its reservoir properties such as porosity, water saturation, and shale content. In order to conclude the ability of application cluster analysis method, the logfacies of well Am-4 that predicated from cluster analysis were compared with the facies studied from examination of cutting samples.

From ocean-bottom cable seismic to porosity volume: A prestack PP and PS analysis of a turbidite reservoir, deepwater Campos Basin, Brazil

The Campos Basin is the best known and most productive of the Brazilian coastal basins. Turbidites are, by far, the main hydrocarbon-bearing reservoirs in the Campos Basin. Using a 4C ocean-bottom cable seismic survey, we set out to improve the reservoir characterization in a deepwater turbidite field in the Campos Basin. To achieve our goal, prestack angle gathers were derived and PP and PS inversion were performed. The inversion was used as an input to predict the petrophysical properties of the reservoir. Converting seismic reflection amplitudes into impedance profiles not only maximizes vertical resolution but also minimizes tuning effects. Mapping the porosity is extremely important in the development of hydrocarbon reservoirs. Combining seismic attributes derived from the PP and PS multicomponent data and porosity logs, we used linear multiregression and neural networking to predict porosity between the seismic attributes and porosity logs at the well locations. After estimating porosity in the well locations, those relationships were applied to the seismic attributes to generate a 3D porosity volume. The porosity volume highlighted the best reservoir facies in the reservoir. The integration of elastic impedance, shear impedance, and porosity improved the reservoir characterization.

Interpretation of multicomponent seismic data across Wister geothermal field, Imperial Valley, California

Multicomponent seismic technology has been implemented across Wister geothermal field in southern California to evaluate the potential for further development of geothermal resources. The seismic survey was positioned atop the San Andreas fault system that extends southward from the Salton Sea. An interpretation of Wister Field geology was made using both P-P and P-SV seismic data. Two formation horizons, Canebrake/Olla/Diablo and Deguynos, were interpreted. Seismic time-structure maps were generated for each horizon. The objective of the study was to determine whether productive geothermal resources could be detected and mapped more reliably with multicomponent seismic data than with single-component P-P data. Complex faults associated with the regional San Andreas Fault system were interpreted across the [Formula: see text] 3D image space. The structural maps created are thought to be some of the most accurate depictions of subsurface structure publicly available in this area of the Imperial Valley. Particular attention was given to documenting faults that cut across deep strata. Both P-P and P-SV seismic showed evidence of such deep faults. Rock properties were analyzed from well logs. Log data showed that clastic rocks at this site exhibited measurable differences in [Formula: see text] velocity ratios for different rock types. Specifically, sand-prone intervals were associated with relatively low [Formula: see text] velocity ratios, and shale-dominated intervals had higher [Formula: see text] ratios. Using this rock physics behavior, [Formula: see text] values derived from seismic traveltime thicknesses were useful for recognizing lithological distributions and identifying favorable reservoir facies. Seismic data across Wister Field, like seismic data across many geothermal fields, have a low signal-to-noise character. We demonstrate that a unified and integrated interpretation of P and S data, even when seismic data quality is not as good as interpreters wish, can still yield valuable information for resource exploitation.

Estimation of Facies Boundaries Using Categorical Indicators with P-Field Simulation and Ensemble Kalman Filter (EnKF)

The Ensemble Kalman Filter (EnKF) often fails to reproduce realistic facies distribution and proportion corresponding to the prior spatial distribution. In this paper, a new step is proposed for inclusion in the history matching of multiple facies reservoir models using EnKF. The new step consists of constructing a facies probability map and application of probability field (P-Field) simulation to re-sample a new ensemble. After certain number of assimilation steps in EnKF, the updated ensemble members are used to propose a probability map for facies distribution. P-Field simulation is performed subsequently using the facies probability map to generate a new ensemble, which honors the static geologic data and is more consistent with the early production data. After the re-sampling step, the forecast model is applied to the new ensemble from the beginning. EnKF is again applied on the ensemble members to assimilate the remaining production history. Two case studies with different facies distribution and well configurations were conducted. Initial ensemble was created using known facies classification at the well locations and populating binary facies data throughout the reservoir using prior information of spatial facies distribution and facies proportions. The qualities of the history-matched models were assessed by comparing the spatial facies distribution and proportions of the updated ensemble, in addition to the root mean square error of the predicted data mismatch. Implementation of EnKF together with re-sampling of the new realizations using probability maps demonstrates reasonable improvement in the history matching and uncertainty assessment of multiple facies reservoir models.

Seismic geomorphology and sequence stratigraphy as tools for the prediction of reservoir facies distribution: an example from the Paleocene and earliest Eocene of the South Buchan Graben, Outer Moray Firth Basin, UKCS

Abstract A seismic stratigraphic analysis constrained by well and wireline log data has been undertaken on the Paleocene and earliest Eocene succession of the South Buchan Graben (Quadrants 20 and 21), Outer Moray Firth Basin (OMFB). Two principal sequences have been described relating to two regressive/transgressive second-order cycles of relative sea-level change. The Maureen, Andrew, Glamis Tuff and Balmoral sandstone members are expressed as a stacked set of lowstand basin floor fans separated by mudstone intervals representing four cycles of third-order relative sea-level change. The Sele and Balder formations contain both basinal and shelfal packages as an expression of two cycles of third-order relative sea-level change. The Forties Sandstone Member is deposited within highly mounded, levee-confined channels downlapped by a prograding slope succession with well-defined clinoforms and deltaic topsets attributed to the Dornoch and Beauly formations. The individual parasequences of the prograding wedge are related to higher-order eustatic fluctuations with incision and slope fans, attributed to the Cromarty Sandstone Member, deposited during periods of relative sea-level lowstand. It is demonstrated that through the integration of lithostratigraphic, seismic geomorphological and sequence stratigraphic analyses an understanding of depositional environments and the distribution of facies within them can be obtained. The identification of basinal and slope features with reservoir potential, along with an understanding of their chronostratigraphic relationship to sealing facies, play an important role in regional play fairway mapping and risk analysis in this area and beyond. Future prospectivity within mature basins, such as the OMFB, relies on subtle stratigraphic traps typical of lowstand systems tracts, where the main risk is associated with reservoir quality and containment.

Characterizing and modeling the Upper Jurassic Arab-D reservoir using outcrop data from Central Saudi Arabia

ABSTRACT Outcrop analogs are used to improve the characterization of reservoir stratigraphy, to understand subsurface facies architecture and heterogeneity, and to overcome the limitations associated with large inter-well spacing within individual oil fields. This study characterized and modeled outcropping strata equivalent to the Upper Jurassic Arab-D carbonate reservoir in Central Saudi Arabia. The study presents qualitative and quantitative sedimentological and petrographic descriptions of lithofacies associations and interprets them within a high-order stratigraphic framework using geostatistical modeling, spectral gamma-ray, geochemistry, petrography and micropaleontology. The sedimentological studies revealed three lithofacies associations, which are interpreted as a gentle slope platform depositional environment comprising nine high-frequency sequences. The biocomponents of the study area show a lower degree of diversity than the subsurface Arab-D reservoir; however, some key biofacies are present and provide indications of the nature of the paleoenvironments. The geochemical results show a strong correlation between the major and trace elements and the reservoir facies, and suggest that the concentrations of elements and their corresponding spectral gamma-ray logs follow the same general upward-shoaling pattern. The 3-D geocellular model captures small-scale reservoir variability, which is reflected in the petrophysical data distribution in the model. This investigation increases the understanding of the stratigraphy of the Arab-D reservoir and provides a general framework for zonation, layering, and lateral stratigraphic correlations.

Geologic and seismic modeling of a coarse-grained deep-water channel reservoir analog (Black’s Beach, La Jolla, California)

The Ardath Shale and Scripps Formation exposed along Blacks Beach north of La Jolla, California, record a deep-water channelized slope system of an Eocene forearc basin. The outcrop exposure, which is approximately 100 m (330 ft) high by 1.7 km (1 mi) long, offers insight into reservoir distribution and connectivity within coarse-grained, confined, deep-water channel systems. To use this outcrop as a quantitative subsurface analog, a detailed two-dimensional lithologic model was constructed from measured sections and interpreted photopanels. Elastic rock properties, including compressional-wave velocity, shear-wave velocity, and density typical of shallow offshore west African reservoirs were used to construct an impedance model. This model was convolved with 15-, 25-, and 50-Hz quadrature-phase Ricker wavelets to generate near- and far-angle stack one-dimensional and two-dimensional synthetic seismic reflection models. Because deep-water lithofacies have distinct amplitude-variation-with-offset behaviors and the interpretation of surfaces is intimately coupled with predicting lithofacies, simple bed interface models of conglomerate, sandstone, interbedded sandstone and mudstone, and muddy sandy debrite were used to build a template for successful interpretation. Interpretation of these forward seismic models demonstrates (1) the limits of and uncertainty associated with the interpretation of seismic data at different frequencies commonly encountered in the exploration, development, and production of deep-water reservoirs; and (2) how the combination of near- and far-angle seismic data can be used to interpret channel-fill lithofacies and improve seismic interpretation. Large-scale channel complex set surfaces with significant impedance contrast (e.g., conglomerate overlying interbedded sandstone and mudstone) are readily interpretable at all frequencies with an increasing vertical error of 5 to 30 m (16 to 98 ft) from 50 to 15 Hz, respectively. Channel and channel complex surfaces can only be accurately mapped on the 50-Hz data, albeit with significant uncertainty. Near- to far-angle stack changes enable the identification of upward-fining, amalgamated, and fine-grained channel-fill lithofacies. Far-angle seismic reflections can provide a more detailed image of boundaries defining channel architecture and reservoir facies distribution.

Geologic assessment of undiscovered oil and gas resources in Aptian carbonates, onshore northern Gulf of Mexico Basin, United States

Carbonate lithofacies of the Lower Cretaceous Sligo Formation and James Limestone were regionally evaluated using established U.S. Geological Survey (USGS) assessment methodology for undiscovered conventional hydrocarbon resources. The assessed area is within the Upper Jurassic–Cretaceous–Tertiary Composite total petroleum system, which was defined for the assessment. Hydrocarbons reservoired in carbonate platform Sligo-James oil and gas accumulations are interpreted to originate primarily from the Jurassic Smackover Formation. Emplacement of hydrocarbons occurred via vertical migration along fault systems; long-range lateral migration also may have occurred in some locations. Primary reservoir facies include porous patch reefs developed over paleostructural salt highs, carbonate shoals, and stacked linear reefs at the carbonate shelf margin. Hydrocarbon traps dominantly are combination structural-stratigraphic. Sealing lithologies include micrite, calcareous shale, and argillaceous lime mudstone. A geologic model, supported by discovery history analysis of petroleum geology data, was used to define a single regional assessment unit (AU) for conventional reservoirs in carbonate facies of the Sligo Formation and James Limestone. The AU is formally entitled Sligo-James Carbonate Platform Oil and Gas (50490121). A fully risked mean undiscovered technically recoverable resource in the AU of 50 million barrels of oil (MMBO), 791 billion cubic feet of natural gas (BCFG), and 26 million barrels of natural gas liquids was estimated. Substantial new development through horizontal drilling has occurred since the time of this assessment (2010), resulting in cumulative production of >200 BCFG and >1 MMBO.

Characteristics of Tight Oil in the Dolomicrite Reservoir: A Case Study of Xingouzui Formation, Jianghan Basin, China

Low-Xingouzui Formation II reservoir in the Xingou region of Jianghan Basin belongs to tight oil reservoir. By means of study about the geochemical characteristics of source rocks, lithology, physical property and pore structure characteristics, this paper confirms that the source rocks of Low-Xingouzui Formation II are mostly above medium in content of organic matter. The hydrocarbon source rocks are mainly of type II. The thermal maturity of most samples is immature-low mature. Dolomicrite and terrigenous clastic (intraclast) dolomite are the most favorable reservoir facies. The reservoir has mid to high porosity and extremely low permeability, and its space is dominated by dolomite dissolution with micro throat pore structure. This oil reservoir distributes widely and quasi continuous, while good conditions of petroleum formation exist. It could hopefully become new increasing point of Jianghan’s oil and gas output that has broad development prospects and studying value.

Reservoir properties and facies characterization from core data and well logging: autochthonous Miocene sediments in the Carpathian Foredeep case study

Laboratory results of total porosity and physical permeability were the basis to calculate Flow Zone Indicator and GR log and porosity log were used for facies identification in the Miocene sandy-shaly sediments in two wells in the Eastern Part of Polish Carpathian Foredeep. There was observed FZI increase with the total porosity from the comprehensive interpretation of logs in the regressive set of parasequences what can be interpreted as better reservoir and hydraulic abilities of them in comparison to transgressive ones. Combining laboratory origin information with well logging results on the basis of facies and FZI correlation worked also as a kind of data scaling.