Bulk Density Logs Research Articles

Pore Pressure Evaluation and Prediction in Esenam Field Northern Depobelt, Niger Delta Nigeria

Pore Pressure Predict ion is a co mmon pract ice before drilling operation in the oil and gas industry. This is very important to avoid surprises such as blowout. Indirect method of pore pressure evaluation and prediction was undertaken in Esenam Field located in the Northern Niger delta basin of Nigeria using wireline log data. The overpressure indicators used are the sonic, resistivity and bulk density logs fro m eight wells drilled in the field. It was revealed that the deeper part of Esenam field (Agbada Format ion) is overpressured. Inference fro m the analysis of sonic and density log data shows that overpressure in this field could primarily be generated by disequilib riu m co mpaction. The depth to the top of overpressure zone falls within the r ange of 2261±5 metres to 2280±10 metres subsea; this is based on the deviation from normal co mpaction trend curve. Pore pressures are accurately predicted using an Eaton exponent of 3.0 and 1.2 for wireline log data.

Regional Stress Variations in the Pembina-Warburg Area of the Alberta Basin: Implications in Coalbed Methane Exploration

This study documents a comprehensive investigation of the in-situ stress magnitude and orientation data from borehole breakouts, mini- and micro-fracture tests, bulk density logs and other stress data, for strata in or adjacent to the Mannville Group and Edmonton Group coals in a part of the west-central Alberta Basin, Canada. The horizontal in-situ stress orientation data can be used to plan horizontal well trajectories in the coal strata of interest to intersect natural fractures and cleats possessing the highest permeability. Horizontal stress orientation data can also be used to assess the effects of well trajectory or borehole collapse risks during drilling, completions, and production operations. Subtle variations in the vertical total stress in the study area may reflect similar trends in the mean effective stress. However, this would need to be confirmed with more complete horizontal stress magnitude and formation pressure data.

Stability analysis of a horizontal coalbed methane well in the Rocky Mountain Front Ranges of southeast British Columbia, Canada

This study describes a wellbore stability analysis undertaken for a horizontal coalbed methane well in the Mist Mountain Formation, SE British Columbia, Canada. Three triaxial compression tests, with ultrasonic velocities, were conducted on 38-mm-diameter core plugs taken from a large, fresh block of Seam 7. Due to the small size of the tested samples, the laboratory-derived strength values were reduced to reflect the in-situ stress conditions considered relevant for a 156-mm-diameter horizontal well. The vertical stress gradient was calculated by integrating a bulk density log from an offset well. Horizontal maximum and minimum stresses were estimated from regional stress data, whereas formation pressure was estimated on the basis of a local hydrological study. The 2D elastoplastic STABView™ numerical modeling code was used to forecast horizontal wellbore stability. The sensitivity of the predicted yielded zone size was examined for varying linear and non-linear rock strength criteria, horizontal in-situ stresses, bottom-hole pressures, formation pressure, drilling depth, and wall-coating efficiency. Stability analysis was performed at bottom-hole pressures ranging from overbalanced to underbalanced in order to simulate the conditions expected during drilling and production. The effects of weak bedding planes and varying well trajectories were also investigated. When drilling at 650 m depth under underbalanced to slightly overbalanced conditions, a high probability of getting the drill pipe stuck was predicted. STABView™ showed that, if the 38-mm-diameter core plug strengths were used directly for forecasting purposes, the predicted yielded zone would be almost 20% overgauge when drilling at balanced conditions. When peak cohesion of coal was reduced by 50% to reflect the conditions expected along weak intervals of a horizontal wellbore, the predicted enlarged borehole was almost 85% overgauge under the same drilling conditions. The most unstable trajectory has N–S azimuth, which is perpendicular to the maximum horizontal stress in the study area. STABView™ indicates that a production liner should be inserted immediately following the drilling of the horizontal well in this structurally complex geologic setting since pressure drawdown and reservoir pressure depletion would undoubtedly lead to enlarged yielded zones and collapse of the wellbore over time.

Combined analysis of different logs in quantification of exhumation and its implications for hydrocarbon exploration, a case study from Australia

Exhumation in the Eromanga Basin of South Australia and Queensland has been quantified using the compaction methodology. The standard method of estimating exhumation using the sonic log has been modified and the adjusted sonic, the bulk density and neutron logs, have been used to estimate exhumation. Additionally the use of a single shale has not been adopted, and seven units, ranging in age from Cretaceous to Jurassic have been analysed. All units yield similar results; and burial at depth greater than currently observed is the most likely cause of overcompaction. The use of the adjusted sonic, bulk and neutron logs have been justified. This study has major implications for hydrocarbon exploration since predicted maturation of source rocks will be greater for any given geothermal history if exhumation is incorporated in maturation modelling.

Multi-attribute seismic analysis - tackling non-linearity

Later, instead of neural networks, a different mathematical approach using cubic b-splines was utilized for the same purpose. The results were found to be similar, suggesting that apart from neural networks, the cubic b-splines could be used as a tool for tackling non-linearity in multi-attribute seismic analysis. AVO inversion for Lame parameters The target area is a Lower Cretaceous glauconite filled fluvial channel, deposited within an incised valley system. A 3D seismic survey was acquired in order to create a stratigraphic model, consistent with all available well control and matching the production history. The ultimate goal was to locate undeveloped potential within the gas sands. The field has been producing since the early 1980s and two of the earliest, most prolific producers have begun to water out. As the objective was stratigraphic in nature, the seismic data were processed with the objective of preserving relative amplitude relationships in the offset domain to allow for the use of AVO attribute analysis. AVO inversion for Lame parameters (λρ and µρ) has become a common practice as it serves to enhance identification of reservoir zones. Also, integration of AVO-derived attribute volumes with other non-AVO derived seismic attribute volumes can provide meaningful geologic information when tied back to well data and verified as correlating with rock properties. Computation of reservoir properties for determination of mathematical relationships between variables derived from well logs, for example, is usually done with non-linear multivariate determinant analysis using neural networks. This paper provides a case study of a 3D seismic survey in southern Alberta, Canada, where a probabilistic neural network solution was first employed on AVO attributes (Pruden, 2002, Chopra & Pruden, 2003). Using the gamma-ray, acoustic and bulk density log curves over the zone of interest, gamma-ray and bulk density inversions were derived from the 3D attribute volumes. This methodology was successful, in that two new drilling locations derived from this work encountered a new gas charged reservoir, that not only extended the life of the gas pool but added new reserves as well.

Neutron Log Measurement of Moisture in Unsaturated Basalt: Progress and Problems

The research described here examines whether neutron logs can be used in unsaturated basalt to quantitatively estimate moisture content, and, in tandem with other wireline logs, to determine the relative contribution to neutron log response by minerals containing chemically bound H. Our results show that it should be possible to quantitatively correlate neutron log response to the amount of both bound and unbound H regardless of saturated or unsaturated conditions. Such a correlation is possible only if bulk density, saturated porosity and neutron log response are already known in saturated conditions. It is not yet known, however, what the exact form of this correlation should be. To evaluate the candidate correlation equations, we compare measured permeability in unsaturated basalts with the calculated H content derived from these correlations. As the result of this evaluation, we identify intervals of clay-free impermeable, unsaturated basalt with apparently high H content. The neutron log response in these intervals may be caused by localized variations of the neutron slowing-down length, Ls, due to low concentration of H in the formation and borehole environment. When Ls is greater than the source-detector spacing of a neutron logging tool, the neutron log response can invert, resulting in potentially faulty interpretation of neutron logs. These measurement uncertainties in unsaturated basalts might be overcome by using a neutron logging tool with both a higher-flux neutron source and increased source-detector spacing, or a neutron tool with several detectors placed at different spacing from the source.

Neutron Log Measurement of Moisture in Unsaturated Basalt: Progress and Problems

The research described here examines whether neutron logs can be used in unsaturated basalt to quantitatively estimate moisture content, and, in tandem with other wireline logs, to determine the relative contribution to neutron log response by minerals containing chemically bound H. Our results show that it should be possible to quantitatively correlate neutron log response to the amount of both bound and unbound H regardless of saturated or unsaturated conditions. Such a correlation is possible only if bulk density, saturated porosity and neutron log response are already known in saturated conditions. It is not yet known, however, what the exact form of this correlation should be. To evaluate the candidate correlation equations, we compare measured permeability in unsaturated basalts with the calculated H content derived from these correlations. As the result of this evaluation, we identify intervals of clay‐free impermeable, unsaturated basalt with apparently high H content. The neutron log response in these intervals may be caused by localized variations of the neutron slowing‐down length, Ls, due to low concentration of H in the formation and borehole environment. When Ls is greater than the source‐detector spacing of a neutron logging tool, the neutron log response can invert, resulting in potentially faulty interpretation of neutron logs. These measurement uncertainties in unsaturated basalts might be overcome by using a neutron logging tool with both a higher‐flux neutron source and increased source‐detector spacing, or a neutron tool with several detectors placed at different spacing from the source.

AN INTEGRATED PETROPHYSICAL WORKFLOW TO GENERATING FLUID SUBSTITUTED LOGS FOR AVO CHARACTERISATION—GIPSY AND NORTH GIPSY FIELDS CASE STUDY, NORTH WEST SHELF, AUSTRALIA

As part of a multi-well field study an integrated petrophysical workflow was developed to include the generation of fluid substituted logs for AVO characterisation.The workflow relied upon the construction of a multimineral model that best approximated the actual mineral content of the reservoir. Any limitations or assumptions were noted and taken into account when creating the multi-mineral model. Other petrophysical results were derived from the same model to validate its consistency such as intrinsic permeability, porosity, water saturation, etc. Iteration between the model and the results was required until a consistent model was achieved.The estimation of an intrinsic permeability log was based upon the k-Lambda method that uses the multimineral model and porosities.The estimation of a shear slowness log and the fluid substituted logs was based upon elastic rock properties derived from the multi-mineral model and the acquired compressional slowness log and bulk density log. This integrated approach provides a higher confidence in the derived results, which are then used as input into the reservoir model, thereby improving the reserve calculations.The interdependence of each derived result on the same input multi-mineral model ensures consistency and predictability in a complex geological environment, which captures all available information.The method is demonstrated with the Gipsy–1 and North Gipsy–1 wells, which were part of the original field study.

An innovative technique resolves apparent anomalies in detection of gas zones based on neutron—density logs

Cross-over effect on neutron—density logs often indicates gas-bearing sands and/or carbonates. Identification of gas based solely on the neutron—density response can be misleading because some gas producing formations may not display a significant (or any) neutron—density cross-over, and some oil-bearing formations may falsely exhibit an appreciable neutron—density cross-over. False gas effects arise from either silt/shale in the reservoir, or from a significant difference between the reservoir matrix density and the standard sandstone/limestone matrix scale generally employed on the density log. True neutron—density gas cross-over effects occur in non-argillaceous formations when the matrix density of the reservoir closely matches the matrix density on the bulk density log. Examples of false gas effects are illustrated in two newly discovered fields, H-field and K-field, in Upper Assam, India. The reservoir in H-field produces gas from a silt—sand sequence, and when the percentage of silt in the reservoir approaches a certain upper limit (about 18%), no cross-over effect is seen in gas-bearing sands on the neutron—density log. An equation has been developed to correct for the presence of silt before making inferences about the presence of gas from neutron—density logs. The second field, K-field, produces oil from thin sands that are typically less than 3 m thick, and false gas effects can be seen on the neutron—density log. The false gas cross-over is caused by a reservoir matrix density that is considerably lower than the standard non-argillaceous sandstone matrix density scale on the bulk density logs. A combination of cross-plots and laboratory measurements is used to derive a modified matrix scale that corrects for false gas effects in the K-field reservoir. These two field case examples in Upper Assam, India, demonstrate that interpretations from wireline logs may be misleading and that correct log analysis requires integration of geology, subsurface test results and production data.

Evolution of tectonic compaction in the Barbados accretionary prism: Estimates from logging-while-drilling

Resistivity and bulk-density logs acquired while drilling are used to document the evolution of porosity, volumetric loss, and effective stress in the upper 300 m of the Barbados accretionary prism. The computed profiles across a thrust fault enable the separation of pre-, syn-, and post-accretion components; total volume loss is divided into normal consolidation (pre-accretion), tectonic volume loss (syn-accretion), and thrust fault loading (post-accretion) in the footwall. Quantitatively, the tectonic volume loss in the Barbados accretionary prism, estimated from the normal consolidation in a reference section, is as large as the pre-accretion volume loss. The compaction history of the accretionary prism is essentially controlled by the vertical displacement of the thrust and the predicted maximum volume loss throughout the prism may be extrapolated from the volume loss trend in the hanging wall. The porosity and effective stress profile at the present time is consistently larger than its corresponding syn-accretion trend and less than the extrapolated maximum from the hanging wall. The present profile is approximately equal to the average of the two curves. The remaining difference in the accretionary prism above the inferred syn-accretion trend is due to post-accretion compaction. The post-accretion volume loss is a physical feedback process due to the superposition of thrust sheets in an accretionary prism. In the case of multiple thrusts developing in a prism, the porosity and effective stress profiles are saw-toothed and approach the maximum tectonic volume loss gradient with depth. The cumulative post-accretion compaction increases with depth and becomes increasingly greater than the pre- and syn-accretion compaction with thickening of the accretionary prism. Post-accretionary loading is the dominant mechanism of volume loss and dewatering in an accretionary prism during its early stages of growth.

Facies Mapping from Three-Dimensional Seismic Data: Potential and Guidelines from a Tertiary Sandstone-Shale Sequence Model, Powderhorn Field, Calhoun County, Texas

We generated a set of three-dimensional (3-D) seismic models of a lower Miocene progradational microtidal shore-zone system at the Powderhorn field, Calhoun County, Texas. These models were based on detailed lithological mapping of 250 m of stratigraphic section over an area of 13 × 9 km. The mapping was guided by detailed facies analysis based on wireline logs from 115 wells. Fourteen sandy depositional units averaging 3-30 m in thickness are encased in 15 shale units. Density-neutron and spontaneous potential (SP) logs in five recently drilled wells were used to calculate effective porosity and shaliness, which correlate well with P-wave velocity and bulk density logs. Those properties were then extended to older wells lacking acoustic, density, and other porosity ogs through regression with SP and resistivity logs to build 3-D properties models, including models of transit time and impedance. The impedance model was mapped from x, y, z to x, y, t, where t is two-way vertical time. The impedance model was converted to primary reflection coefficient series that were then convolved with zero-phase wavelets of different frequencies to produce the seismic models. The results show how the depositional facies at reservoir scale might be illustrated by 3-D seismic data, and how the seismic resolution of depositional facies changes with seismic frequency, stratigraphic position, and facies patterns. The Powderhorn reservoir sequence is interpreted as a barrier bar/lagoon depositional system associated with coastal stream plains, bayhead deltas, and small wave-dominated deltas corresponding to frequent relative changes of sea level. To detect these types of deposits, the seismic frequency should be selected such that the seismic data are tuned to the maximum thickness to establish a linear relationship between seismic amplitude and facies, and to achieve the best signal-to-noise ratio. The facies associated with the environments where main sandstones are surrounded by muddy deposits, such as coastal stream plain, bayhead delta, delta plain, and backbarrier/lagoon transition, are well illustrated in our seismic model. Lack of muddy deposits, for example in a wave-dominated delta, c uld result in obscure facies boundaries and therefore unclear lithofacies patterns. In this study, poorly compacted clean sandstone and pure shale have similar impedances, and consequently produce similar seismic responses. The resulting ambiguity may be reduced by careful analysis of facies relationships if some well data are available, and probably by the amplitude vs. offset (AVO) method. The stratal resolution of seismic imagery depends not only on wavelet frequency, but also on the stratigraphic position of a given reservoir, or the magnitude of geological interference.

Upper Jurassic sandstone reservoir quality and distribution on the Fladen Ground Spur

Abstract During the Oxfordian to Early Kimmeridgian much of the Fladen Ground Spur was a positive feature and sourced clastic deposition in the Piper Basin, Witch Ground and South Viking grabens. The eudoxus flooding event introduced shallow marine conditions onto the Fladen Ground Spur, and during the continuing transgression, a veneer of clastic sediments was deposited. Three facies units are defined: facies 1 — thin, low-high-energy glauconitic sandstone; facies 2 — medium-high-energy clean, well-sorted medium-grained sandstone; facies 3 — low-energy, fine-grained argillaceous sandstone. Reservoir quality is evaluated using porosity data from neutron porosity and bulk density logs. Porosity-permeability cross-plots provide a workable relationship for permeability prediction in uncored wells. Initial results show that, predictably, facies 2 sandstone has the best poroperm characteristics. Facies 1 sandstone contains locally derived clasts, the diverse nature of which affects reservoir quality. Subcrop is interpreted to be an important, if not causal, factor that controls reservoir quality in facies 1 sandstone.

Effects of Diagenesis on Enhanced-Resolution Bulk Density Logs in Tertiary Gulf Coast Sandstones: An Example from the Lower Vicksburg Formation, McAllen Ranch Field, South Texas

Diagenetic heterogeneity strongly influences porosity and permeability distribution in sandstone reservoirs of the lower Vicksburg Formation. Enhanced-resolution bulk density logs, which use a 3-cm (1.2-in.) rather than the standard 15-cm (6-in.) sampling increment, offer important new information in understanding diagenetically complex sandstones in the subsurface. Detailed petrographic mapping and sedimentologic description of core from the Oligocene lower Vicksburg Formation of McAllen Ranch field, south Texas, have identified cement variations that result in diagenetic zones ranging in thickness from 0.1 cm (0.04 in.) to 0.9 m (3 ft). The petrographic and petrophysical properties of these diagenetic zones define three diagenetic facies that can be correlated with log esponse from the enhanced-resolution bulk density log: (1) the quartz-cemented facies, averaging 13% porosity and 0.342 md permeability, and having a recorded density greater than or equal to 2.43 g/cm3 but less than 2.48 g/cm3, (2) the chlorite-cemented facies, averaging 16.7% porosity and 0.193 md permeability, and having a recorded density less than 2.43 g/cm3, and (3) the calcite- or transitional-cemented facies, averaging 9.4% porosity and 0.04 md permeability, and having a recorded density greater than or equal to 2.48 g/cm3. Intervals cemented with different minerals are identified by the enhanced-resolution bulk density log based on the ranges in density that define each diagenetic facies. This identification of diagenetic facies not only influences the accurate determination of the net sandstone thickness and porosity of reservoirs within the lower Vicksburg Formation, but also directly controls permeability calculations. For example, classification of cement intervals from lower Vicksburg gas reservoirs using enhanced-resolution bulk density logs and porosity and permeability regressions for each of the diagenetic facies results in estimated permeability thicknesses as much as 50% greater than those calculated using standard log analysis. Because standard log analysis ignores the effects of diagenetic eterogeneity, the use of the enhanced-resolution bulk density log provides significant information that leads to more accurate reservoir and field evaluations in diagenetically complex sandstones.

Effects of Diagenesis on Enhanced-Resolution Bulk Density Logs in Tertiary Gulf Coast Sandstones: An Example from the Lower Vicksburg Formation: ABSTRACT

Effects of Diagenesis on Enhanced-Resolution Bulk Density Logs in Tertiary Gulf Coast Sandstones: An Example from the Lower Vicksburg Formation: ABSTRACT

Resolution of Complex Minnelusa Stratigraphy, Powder River Basin, Wyoming, Using an Interactive Workstation-Based Interpretation Environment: ABSTRACT

The Permian Minnelusa Formation of the Powder River basin is a complex of cyclic shoreline eolian sands and nearshore reworked sands, evaporites, and carbonates. Hydrocarbons occur in secondary porosity created by late-stage facies-dependent dissolution of anhydrite cement. Trapping is by lateral facies changes and by paleotopographically formed structural anomalies. Stratigraphic trends change abruptly and, therefore, create serious geologic interpretation and mapping problems. Correlation of rock units using only raw petrophysical curves is difficult. However, correlations based on lithology are easier to make and have a firmer stratigraphic basis. Lithology was determined by numerical analysis of the sonic travel time, neutron porosity, gamma ray, and bulk-density log suite. Analysis results were digitally stored as log curves representing percentages of shale, anhydrite, dolomite, quartz, and porosity. Displays of these curves were used for correlation. Summary statistics from specific depth intervals were used for mapping lithologies. Lithofacies cross sections and maps, conventional cross sections and structure contour maps, and fluid production maps were used to interpret the petroleum geology of the study area.

Modeling the occurrence of overpressures on the Scotian Shelf, offshore eastern Canada

Many wells on the Scotian Shelf, offshore from Nova Scotia, have drilled into overpressured zones. In particular, the wells comprising the Venture gas field have all encountered overpressures at depths below 4.5 km. The characteristics of the overpressure zones in the Venture field vary in some important details from overpressured zones on the U.S. Gulf Coast. In the Venture field the shales in the overpressured zones are observed to be normally compacted and interbedded with layers of overpressured sandstones. This is in contrast to the Gulf Coast, where the shales in the overpressure zone are undercompacted. Resistivity logs, sonic logs, and bulk density logs all provide some indications of overpressures in the Venture field but are not as unequivocal indicators of overpressure as they are on the Gulf Coast. Theoretical investigations of the causes of overpressures in an environment such as the Venture field show that overpressures are unlikely to be caused by loading of sediments. The most probable cause of overpressures is recent and continuing fluid generation, which is related to the transformation of kerogen to hydrocarbons. Limits are placed on the average permeabilities and fluid generation rates which are required if overpressures are to be produced by fluid generation.

Experiment on Estimating Thermal Conductivity of Sedimentary Rocks from Oil Well Logging: GEOLOGIC NOTE

Oil well are an important source of geothermal data for studying regional tectonics, reconstructing the evolution of sedimentary basins, and theorizing petroleum generation, migration, and accumulation. A more satisfactory, less laborious method of estimating the thermal conductivity of sedimentary rocks is badly needed. The thermal conductivity of cores from two gas wells in France was measured and correlated with neutron porosity index, sonic interval travel time, bulk density, and gamma-ray logs. To obtain reasonable predictions of conductivity, data were segregated into lithologic groups such as sand-shale, carbonate-shale, and carbonate-sand. A set of regression coefficients in the equation that predicts the conductivity from the logs was calculated for each group. T e correlation coefficients between the measured and predicted conductivities of the core samples were 0.81, 0.75, and 0.61, respectively, for the three lithologic groups. The average percent difference between the measured and the calculated conductivities for the lithologies likely to be encountered in practice is 13.4%. We expect this figure can be reduced to 10% by enlarging the data base for calculating the regression coefficients. In the same basin or oil field, the relative errors from well to well probably will be 6% or smaller because the lithology will be nearly homogeneous.

Computer-Aided Geological Characterization of a Sandstone Reservoir, North Ward Estes Field, Ward and Winkler Counties, Texas: ABSTRACT

The North Ward Estes field is located along the western edge of the Central Basin platform in Ward and Winkler Counties, Texas. The field is part of an upper Guadalupian productive trend that extends uninterrupted for 90 mi on the edge of the platform. The North Ward Estes field has produced over 350 million bbl of oil (one-third of the trend's cumulative production) from more than 3,000 wells since its discovery in 1929. Production in the field is from back-reef lagoonal siliciclastics (sandstones) of the Yates, Seven Rivers, and Queen Formations. A correlation scheme was developed for the field based on laterally continuous key dolomites that bracket the productive sands and segment the reservoir into discrete mappable units. Applying this scheme, more than 60,000 correlation markers were selected and loaded into a computer database. Concurrently, 15 million curve feet of log data and 30,000 ft of core analysis data were digitized. Core analyses were depth corrected. Logs were normalized using a 60-ft interval of laterally continuous anhydritic dolomite. Core porosity data were cross plotted vs. bulk-density log values to develop equations (transforms) for derivation of porosity. Corrections for hole rugosity, overburden pressure, and lithologic complications were applied to refine themore » porosity transform. Structure and porosity-feet maps were then merged with fluid contact and water saturation data to calculate volumetrics.« less

Clay and Framework Mineralogy, Cation Exchange Capacity, Matrix Density, and Porosity from Geochemical Well Logging in Kern County, California: ABSTRACT

Elemental concentrations of several inorganic elements were determined in a continuous basis with depth using the Schlumberger gamma-ray spectrometry (GST) and natural gamma-ray spectrometry (NGS) logs in a Santa Fe Energy Company well in the Kern Front field in Bakersfield, California. Logs of Al, Si, Ca, K, Fe, Ti, and non-pore H were processed by a matrix multiplication procedure, used previously for a Venezuelan well, into estimated abundances of quartz, feldspar, calcite, ilmenite, and the clay minerals kaolinite, illite, and smectite. A total of 64 core-plug samples were analyzed for elemental content by x-ray fluorescence and neutron activation analysis and for mineralogy by bulk and < 4 ..mu.. clay x-ray diffraction analyses. Log-derived elemental concentrations and mineral abundances show good agreement with the core values. Cation exchange capacity (CEC) is estimated from the abundances of the clay minerals and typical values for these clays. The CEC log agrees well with CEC values determined on the core samples. The mineral abundance logs also permit an estimation of the average matrix density as a function of depth, derived from typical grain densities for each mineral phase. This matrix density log, combined with the bulk density log, yields a porosity log that comparesmore » well with over 200 measurements on core.« less

Statistical Model for Source Rock Maturity and Organic Richness Using Well-Log Data, Bakken Formation, Williston Basin, United States: GEOLOGIC NOTES

A study of the Bakken Formation, the proposed source rock for much of the hydrocarbons generated in the Williston basin, was done using bulk density, neutron porosity, and resistivity logs, and formation temperatures. Principal components, cluster, and discriminant analyses indicate that the present-day distribution of organic matter controls much of the variability in the log values. Present-day total organic carbon values are high in the central part of the basin near northeastern Montana and along the east edge of the basin, and low in the area of the Nesson anticline and along the southwest edge of the basin. Using a regression of density on temperature and the analysis of residuals from this regression, hydrocarbon maturity effects were partially separated from depos tional effects. These analyses suggest that original concentrations of organic matter were low near the limits of the Bakken and increased to a high in northeastern Montana. The pre-maturation distribution of total organic carbon and the present-day total organic carbon distribution, as determined by statistical analyses of well-log data, agree with the results of geochemical analyses. The distributions can be explained by a relatively simple depositional pattern and thermal history for the Bakken.