Salman Bloch

Bio: Salman Bloch is an academic researcher from ARCO. The author has contributed to research in topics: Petroleum reservoir & Diagenesis. The author has an hindex of 8, co-authored 15 publications receiving 598 citations.

Anomalously high porosity and permeability in deeply buried sandstone reservoirs: Origin and predictability

Abstract: Porosity and permeability generally decrease with increasing depth (thermal exposure and effective pressure); however, a significant number of deep (>4 km [approximately 13,000 ft]) sandstone reservoirs worldwide are characterized by anomalously high porosity and permeability. Anomalous porosity and permeability can be defined as being statistically higher than the porosity and permeability values occurring in typical sandstone reservoirs of a given lithology (composition and texture), age, and burial/temperature history. In sandstones containing anomalously high porosities, such porosities exceed the maximum porosity of the typical sandstone subpopulation. Major causes of anomalous porosity and permeability were identified decades ago; however, quantification of the effect of processes responsible for anomalous porosity and permeability and the assessment of the predictability of anomalous porosity and permeability occurrence in subsurface sandstones have rarely been addressed in published literature. The focus of this article is on quantification and predictability of three major causes of anomalously high porosity: (1) grain coats and grain rims, (2) early emplacement of hydrocarbons, and (3) shallow development of fluid overpressure. Grain coats and grain rims retard quartz cementation and concomitant porosity and permeability reduction by inhibiting precipitation of quartz overgrowths on detrital-quartz grains. Currently, prediction of anomalous porosity associated with grain coats and grain rims is dependent on the availability of empirical data sets. In the absence of adequate empirical data, sedimentologic and diagenetic models can be helpful in assessing risk due to reservoir quality. Such models provide a means to evaluate the effect of geologic constraints on coating occurrence and coating completeness required to preserve economically viable porosity and permeability (Begin page 302) in a given play or prospect. These constraints include thermal history and sandstone grain size and composition. The overall effect of hydrocarbon emplacement on reservoir quality is controversial. It appears that at least some cements (quartz and illite) may continue to precipitate following emplacement of hydrocarbons into the reservoir. Our work indicates that integration of basin modeling with reservoir quality modeling can be used to quantify, prior to drilling, the potential impact of hydrocarbon emplacement on porosity and permeability. The best-case scenario for significant reservoir quality preservation due to fluid overpressure development is in rapidly deposited Tertiary or Quaternary sandstones. Our models suggest that significant porosity can be preserved in sandstones that have experienced continuous high fluid overpressures from shallow burial depths. The models also indicate that the potential for porosity preservation is greatest in ductile-grain-rich sandstones because compaction tends to be the dominant control on reservoir quality in such rocks. The case for significant porosity preservation associated with fluid overpressures in pre-Tertiary basins, however, is more problematic because of the complexities in the history of fluid overpressure and the greater significance of quartz cementation as a potential mechanism of porosity loss.

Approaches to Predicting Reservoir Quality in Sandstones

Abstract: Despite limited understanding of the details of many diagenetic processes, empirical techniques can be used effectively to predict reservoir quality prior to drilling. The predictive approach depends mainly on the availability of empirical data in the area of interest. In frontier basins, mean or maximum porosity of a potential sandstone reservoir can be estimated for a given composition and level of thermal exposure (or burial depth). The reliability of the estimates is constrained by input data. Approximate values of input parameters can be obtained from seismic data in combination with geological analysis of the area. In basins with sufficient information to generate calibration data sets, the predictive technique uses regression analysis. The applicability of this approach is constrained by the limits imposed by the calibration data set and is generally limited to samples containing less than 10% pore-filling cement. Quartz-rich sandstones (>85% framework quartz), cemented with quartz, are an exception to the 10% limit because quartz cementation commonly is related to burial history and rock texture. In weakly cemented sandstones, the critical variables controlling porosity are detrital composition, sorting, and burial history. Permeability can be predicted independently of porosity using the same variables plus grain size. These variables can be evaluated from seismic data and facies models. T is approach is best suited either for sandstones in which compaction is the main porosity-reducing process or for quartz-rich sandstones. An adequate predictive model for sandstone suites with a wide range of cement content can be obtained by dividing the calibration data set into two or more subsets and developing a predictive model for each. For example, one subset can be limited to samples with less than 10% cement, whereas the second subset will consist of samples with more than 10% nonquartz cement. Porosity and permeability in the first subset are then expressed by linear regression, whereas controls on reservoir quality in the more heavily cemented sandstones are determined independently based on understanding of cement distribution patterns.

Petroleum-Related Origin for Uraniferous Organic-Rich Nodules of Southwestern Oklahoma

Abstract: Geologic field relations and geochemical analyses imply a petroleum-related origin for the organic matter of uraniferous nodules in the Permian Hennessey Group red beds in Kiowa County, Oklahoma. The local presence of crude oil in the shallow subsurface and the absence of local occurrences of plant debris suggest a hydrocarbon-related origin for these nodules. Several oil seeps in the general vicinity of the study area indicate that major steep reverse faults near the nodule site may have provided vertical conduits for petroleum migration from deeper zones. Geochemical analyses of the uraniferous nodules, including infrared spectroscopy and elemental analysis, reveal characteristics of both coal and petroleum. Carbon isotopic analyses favor a petroleum-related origin. A model incorporating field and geochemical evidence is suggested whereby crude oil, migrating from depth, is initially altered near the surface to a more viscous material. Concurrently migrating uranium-bearing ground water is then stripped of its uranium by the degraded petroleum. Therefore, presence of such nodules in the shallow subsurface may suggest buried petroleum deposits. Confirmation of this model must await further study of the effects of radiation damage on organic matter.

Porosity prediction, prior to drilling, in sandstones of the Kekiktuk Formation (Mississippian), North Slope of Alaska

Abstract: Porosity in sandstones of the Kekiktuk Formation was successfully estimated prior to drilling of the 1 Leffingwell wildcat well (North Slope of Alaska). The estimate was based on a calibration dataset used to evaluate the effects of (1) framework grain composition, (2) depositional facies, and (3) postdepositional processes on porosity of Kekiktuk sandstones. The sandstones of the Kekiktuk Formation are chert-bearing sublitharenites and quartzarenites characterized by a homogeneous composition of the detrital framework in the study area. Thus, mineral composition is not a major factor responsible for differences in reservoir quality. Based on outcrop and available core observations, the Kekiktuk Formation was interpreted to include several wet fan-deltas. The depositional model suggested that the 1 Leffingwell well would penetrate the distal, fine-grained facies of one such system. A petrographic study indicated that in fine- and very fine-grained Kekiktuk sandstones, such as those predicted in the wildcat, porosity was reduced primarily by silica cementation. Silica cementation, in turn, is related to burial history. Because of the relationship among porosity, silica cementation, and burial history, burial history diagrams provided a measure of the effect of burial history on porosity in available calibration wells. A synthetic burial history curve was constructed prior to drilling of the 1 Leffingwell well from available seismic data. This burial history curve was then used to estimate the well's porosity based on the previously established porosity-burial history relationship.

Modes of formation of anomalously high radioactivity in oil-field brines

Abstract: Many oil-field brines contain anomalously high radium concentrations. A theoretical model proposed here suggests that such concentrations can be a function of the geochemical environments of petroleum reservoirs or can be caused by uranium occurrences associated with oil pools. The model suggests that, on a triangular diagram with barium, radium-228, and radium-226 as the axes, brines associated with uranium occurrences will plot relatively far toward the radium-226 corner. Radium-rich brines associated with "normal" mineral assemblages will fall relatively close to the Ba/Ra-228 side of the diagram. Geochemical differentiation of the radium source may provide a useful tool in exploration for uranium accumulations in petroliferous areas.

Width and Thickness of Fluvial Channel Bodies and Valley Fills in the Geological Record: A Literature Compilation and Classification

Abstract: The three-dimensional geometry of fluvial channel bodies and valley fills has received much less attention than their internal structure, despite the fact that many subsurface analyses draw upon the geometry of suitable fluvial analogues. Although channel-body geometry has been widely linked to base-level change and accommodation, few studies have evaluated the influence of local geomorphic controls. To remedy these deficiencies, we review the terminology for describing channel-body geometry, and present a literature dataset that represents more than 1500 bedrock and Quaternary fluvial bodies for which width (W) and thickness (T) are recorded. Twelve types of channel bodies and valley fills are distinguished based on their geomorphic setting, geometry, and internal structure, and log-log plots of W against T are presented for each type. Narrow and broad ribbons (W/T 1000, respectively) are distinguished. The dataset allows an informed selection of analogues for subsurface applications, and spreadsheets and graphs can be downloaded from a data repository. Mobile-channel belts are mainly the deposits of braided and low-sinuosity rivers, which may exceed 1 km in composite thickness and 1300 km in width. Their overwhelming dominance throughout geological time reflects their link to tectonic activity, exhumation events, and high sediment supply. Some deposits that rest on flat-lying bedrock unconformities cover areas > 70,000 km2. In contrast, meandering river bodies in the dataset are < 38 m thick and < 15 km wide, and the organized flow conditions necessary for their development may have been unusual. They do not appear to have built basin-scale deposits. Fixed channels and poorly channelized systems are divided into distributary systems (channels on megafans, deltas, and distal alluvial fans, and in crevasse systems and avulsion deposits), through-going rivers, and channels in eolian settings. Because width/maximum depth of many modern alluvial channels is between 5 and 15, these bodies probably record an initial aspect ratio followed by modest widening prior to filling or avulsion. The narrow form (W/T typically < 15) commonly reflects bank resistance and rapid filling, although some are associated with base-level rise. Exceptionally narrow bodies (W/T locally < 1) may additionally reflect unusually deep incision, compactional thickening, filling by mass-flow deposits, balanced aggradation of natural levees and channels, thawing of frozen substrates, and channel reoccupation. Valley fills rest on older bedrock or represent a brief hiatus within marine and alluvial successions. Many bedrock valley fills have W/T < 20 due to deep incision along tectonic lineaments and stacking along faults. Within marine and alluvial strata, upper Paleozoic valley fills appear larger than Mesozoic examples, possibly reflecting the influence of large glacioeustatic fluctuations in the Paleozoic. Valley fills in sub-glacial and proglacial settings are relatively narrow (W/T as low as 2.5) due to incision from catastrophic meltwater flows. The overlap in dimensions between channel bodies and valley fills, as identified by the original authors, suggests that many braided and meandering channel bodies in the rock record occupy paleovalleys. Modeling has emphasized the importance of avulsion frequency, sedimentation rate, and the ratio of channel belt and floodplain width in determining channel-body connectedness. Although these controls strongly influence mobile channel belts, they are less effective in fixed-channel systems, for which many database examples testify to the influence of local geomorphic factors that include bank strength and channel aggradation. The dataset contains few examples of highly connected suites of fixed-channel bodies, despite their abundance in many formations. Whereas accommodation is paramount for preservation, its influence is mediated through geomorphic factors, thus complicating inferences about base-level controls.

The impact of diagenesis on the heterogeneity of sandstone reservoirs: A review of the role of depositional facies and sequence stratigraphy

Abstract: Diagenesis exerts a strong control on the quality and heterogeneity of most clastic reservoirs. Variations in the distribution of diagenetic alterations usually accentuate the variations in depositional porosity and permeability. Linking the types and distribution of diagenetic processes to the depositional facies and sequence-stratigraphic framework of clastic successions provides a powerful tool to predict the distribution of diagenetic alterations controlling quality and heterogeneity. The heterogeneity patterns of sandstone reservoirs, which determine the volumes, flow rates, and recovery of hydrocarbons, are controlled by geometry and internal structures of sand bodies, grain size, sorting, degree of bioturbation, provenance, and by the types, volumes, and distribution of diagenetic alterations. Variations in the pathways of diagenetic evolution are linked to (1) depositional facies, hence pore-water chemistry, depositional porosity and permeability, types and amounts of intrabasinal grains, and extent of bioturbation; (2) detrital sand composition; (3) rate of deposition (controlling residence time of sediments at specific near-surface, geochemical conditions); and (4) burial thermal history of the basin. The amounts and types of intrabasinal grains are also controlled by changes in the relative sea level and, therefore, can be predicted in the context of sequence stratigraphy, particularly in paralic and shallow marine environments. Changes in the relative sea level exert significant control on the types and extent of near-surface shallow burial diagenetic alterations, which in turn influence the pathways of burial diagenetic and reservoir quality evolution of clastic reservoirs. Carbonate cementation is more extensive in transgressive systems tract (TST) sandstones, particularly below parasequence boundaries, transgressive surface , and maximum flooding surface because of the abundance of carbonate bioclasts and organic matter, bioturbation, and prolonged residence time of the sediments at and immediately below the sea floor caused by low sedimentation rates, which also enhance the formation of glaucony. Eogenetic grain-coating berthierine, odinite, and smectite, formed mostly in TST and early highstand systems tract deltaic and estuarine sandstones, are transformed into ferrous chlorite during mesodiagenesis, helping preserve reservoir quality through the inhibition of quartz cementation. The infiltration of grain-coating smectitic clays is more extensive in braided than in meandering fluvial sandstones, forming flow barriers in braided amalgamated reservoirs, and may either help preserve porosity during burial because of quartz overgrowth inhibition or reduce it by enhancing intergranular pressure dissolution. Diagenetic modifications along sequence boundaries are characterized by considerable dissolution and kaolinization of feldspars, micas, and mud intraclasts under wet and warm climates, whereas a semiarid climate may lead to the formation of calcrete dolocrete cemented layers. Turbidite sandstones are typically cemented by carbonate along the contacts with interbedded mudrocks or carbonate mudstones and marls, as well as along layers of concentration of carbonate bioclasts and intraclasts. Commonly, hybrid carbonate turbidite arenites are pervasively cemented. Proximal, massive turbidites normally show only scattered spherical or ovoid carbonate concretions. Improved geologic models based on the connections among diagenesis, depositional facies, and sequence-stratigraphic surfaces and intervals may not only contribute to optimized production through the design of appropriate simulation models for improved or enhanced oil recovery strategies, as well as for CO2 geologic sequestration, but also support more effective hydrocarbon exploration through reservoir quality prediction.

Sandstone diagenesis and reservoir quality prediction: Models, myths, and reality

Abstract: Models and concepts of sandstone diagenesis developed over the past two decades are currently employed with variable success to predict reservoir quality in hydrocarbon exploration. Not all of these are equally supported by quantitative data, observations, and rigorous hypothesis testing. Simple plots of sandstone porosity versus extrinsic parameters such as current subsurface depth or temperature are commonly extrapolated but rarely yield accurate predictions for lithified sandstones. Calibrated numerical models that simulate compaction and quartz cementation, when linked to basin models, have proven successful in predicting sandstone porosity and permeability where sufficient analog information regarding sandstone texture, composition, and quartz surface area is available. Analysis of global, regional, and local data sets indicates the following regarding contemporary diagenetic models used to predict reservoir quality. (1) The effectiveness of grain coatings on quartz grains (e.g., chlorite, microquartz) as an inhibitor of quartz cementation is supported by abundant empirical data and recent experimental results. (2) Vertical effective stress, although a fundamental factor in compaction, cannot be used alone as an accurate predictor of porosity for lithified sandstones. (3) Secondary porosity related to dissolution of framework grains and/or cements is most commonly volumetrically minor (2%). Exceptions are rare and not easily predicted with current models. (4) The hypothesis and widely held belief that hydrocarbon pore fluids suppress porosity loss due to quartz cementation is not supported by detailed data and does not represent a viable predictive model. (5) Heat-flow perturbations associated with allochthonous salt bodies can result in suppressed thermal exposure, thereby slowing the rate of quartz cementation in some subsalt sands.

Anomalously high porosity and permeability in deeply buried sandstone reservoirs: Origin and predictability

Abstract: Porosity and permeability generally decrease with increasing depth (thermal exposure and effective pressure); however, a significant number of deep (>4 km [approximately 13,000 ft]) sandstone reservoirs worldwide are characterized by anomalously high porosity and permeability. Anomalous porosity and permeability can be defined as being statistically higher than the porosity and permeability values occurring in typical sandstone reservoirs of a given lithology (composition and texture), age, and burial/temperature history. In sandstones containing anomalously high porosities, such porosities exceed the maximum porosity of the typical sandstone subpopulation. Major causes of anomalous porosity and permeability were identified decades ago; however, quantification of the effect of processes responsible for anomalous porosity and permeability and the assessment of the predictability of anomalous porosity and permeability occurrence in subsurface sandstones have rarely been addressed in published literature. The focus of this article is on quantification and predictability of three major causes of anomalously high porosity: (1) grain coats and grain rims, (2) early emplacement of hydrocarbons, and (3) shallow development of fluid overpressure. Grain coats and grain rims retard quartz cementation and concomitant porosity and permeability reduction by inhibiting precipitation of quartz overgrowths on detrital-quartz grains. Currently, prediction of anomalous porosity associated with grain coats and grain rims is dependent on the availability of empirical data sets. In the absence of adequate empirical data, sedimentologic and diagenetic models can be helpful in assessing risk due to reservoir quality. Such models provide a means to evaluate the effect of geologic constraints on coating occurrence and coating completeness required to preserve economically viable porosity and permeability (Begin page 302) in a given play or prospect. These constraints include thermal history and sandstone grain size and composition. The overall effect of hydrocarbon emplacement on reservoir quality is controversial. It appears that at least some cements (quartz and illite) may continue to precipitate following emplacement of hydrocarbons into the reservoir. Our work indicates that integration of basin modeling with reservoir quality modeling can be used to quantify, prior to drilling, the potential impact of hydrocarbon emplacement on porosity and permeability. The best-case scenario for significant reservoir quality preservation due to fluid overpressure development is in rapidly deposited Tertiary or Quaternary sandstones. Our models suggest that significant porosity can be preserved in sandstones that have experienced continuous high fluid overpressures from shallow burial depths. The models also indicate that the potential for porosity preservation is greatest in ductile-grain-rich sandstones because compaction tends to be the dominant control on reservoir quality in such rocks. The case for significant porosity preservation associated with fluid overpressures in pre-Tertiary basins, however, is more problematic because of the complexities in the history of fluid overpressure and the greater significance of quartz cementation as a potential mechanism of porosity loss.