Neutron-density Logs Research Articles

Evaluating Petrophysical Properties of Sa'di Reservoir in Halfaya Oil Field

The petrophysical characteristics of five wells drilled into the Sa'di Formation in the Halfaya oil field were evaluated using IP software to determine a reservoir and explore hydrocarbon reserve zones. The lithology was evaluated using the M-N cross-plot method. The diagram showed that the Sa'di Formation was mainly composed of calcite (represented by the limestone region) is the main mineral in the Sa′di Reservoir. Using a density-neutron cross plot to identify the lithology showed that the formation mainly consists of limestone with minor shale. Gamma-ray logs were employed to calculate the shale quantity in each well. The porosity at weak hole intervals was calculated using a sonic log and neutron-density log at the reservoir unit. Additionally, Archie's equation is applied to calculate fluid saturation using resistivity data. The reservoir water saturation in the uninvaded zone is calculated using Archie's equation, which determines the most essential element utilized in log evaluation. Finally, the permeability was measured using a flow zone indicator. The results indicate that the limestone and shale that the cuttings description report enhanced comprise most of the Sa'di reservoir. At the HF-316 and HF-21 wells, the core porosity was verified. In an uninvaded zone, the Archie equation offers the best estimation. Three equations were derived from the core data's porosity-permeability connection using a cross-plot of the reservoir quality index and normalized porosity index. According to the general interpretation, zones B1, B2, and B3 contain the most hydrocarbons; however, the B2 zone, the best layer in the Sa'di reservoir, has the highest hydrocarbon concentration. This is close to previous studies and field results. Finally, Sa'di A is formed mainly of mud lime and contains no hydrocarbons. As a result, Sa'di A was separated into A1 and A2 based on the percentage of shale difference.

A novel physics-based resolution improvement method for neutron-density log

In the later stages of oilfield development, the accurate identification of thin reservoirs become increasingly crucial for oil and gas exploration. However, conventional logs have limited vertical resolution, making it challenging to identify thin reservoirs. This results in potential hydrocarbon layers getting overlooked during exploration. To address this issue, a novel resolution enhancement method for density and neutron porosity logs based on physical constraint optimization is proposed. The proposed method involves three main steps: (1) developing an objective function that relates the true formation density and porosity to the measurement based on the physics of nuclear, (2) setting density neutron cross-constraints using the volumetric model of logging interpretation, and (3) establishing the objective function matrix equations using sliding window technology and solving the matrix equations using the constrained least square method to obtain high-resolution density and neutron porosity logs. The proposed method is evaluated using both synthetic and field logs obtained from compensated density and compensated neutron tools. The results demonstrate an effective improvement in neutron porosity and density log resolution to 15 cm, which is significantly enhanced compared to the typical vertical resolution of 2 ft. This study offers a new perspective for enhancing the resolution of logs and contributes to the exploration and development of thin oil and gas resources. And the proposed method could be used in future exploration and production projects to identify potential hydrocarbon layers that might have been overlooked by conventional logs.

Petrophysical Analysis of Mars Field Offshore Dahomey Basin Nigeria

Petrophysical evaluation of the Mars Field in the Dahomey Basin, Nigeria was done to identify and analyze petrophysical properties of the reservoirs in the field. This was achieved by the use of 3 wells from the field. This research determines the lithology, shale volume (Vsh), porosity (Φ), permeability (K), fluid saturation. Two hydrocarbon-bearing reservoirs age from three wells were identified which was then subdivided into different levels in this research. The average permeability value of the reservoirs is 20.0140md while porosity value ranges between 18%-39%. Fluid types within the reservoir were identified to be Gas, Oil, Condensate and water based on the Neutron-Density log motif. The petrophysical analysis of the field reveals that reservoir porosity ranges from 11-26%, hydrocarbon saturation ranges from 0.07-0.91, water saturation ranges from 0.93-0.09, volume of shale ranges from 0.09-0.22 and net-to-gross ranges from 0.46-0.878. From this research it was identified that the prolific reservoir within the Dahomey basin is within the Turonian and Cenomanian reservoir with good quality reservoir and producible hydrocarbon saturation. Keywords:Dahomey/Benin Basin; Petrophysics; Volume of shale; Porosity; Water saturation; Potential reservoir; Turonian; Cenomanian.

A Revised Gassmann Fluid Replacement Model Based on Neutron-Density Logs in Shaly Sandstone Reservoirs

Summary Fluid-replacement modeling (FRM) is a fundamental step in rock physics scenario modeling. The results help to conduct forward modeling for prediction of seismic signatures. Further, the analysis of the results improves the accuracy of quantitative interpretation and leads to an updated reservoir characterization. While modeling for different possible reservoir pore fluid scenarios, the quality of the results largely depends on the accuracy of the FRM. Gassmann (1951)fluid-replacement modeling (GFRM) is one of the widely adopted methods across the oil and gas industry. However, the Gassmann method assumes the reservoir as clean sandstone with connected pores. This causes Gassmann fluid-replacement results to overestimate the fluid effect in shaly sandstones. This study uses neutron and density logs to correct the overestimated results in shaly sandstone reservoirs. Due to the nature of these recordings, both of these log readings have close dependencies on the presence of shale. When the logs are plotted in a justified scale, the differences between the logs provide an accurate measurement of shaliness within the reservoir. The study has formulated a weight factor using the logs, which has further been used to scale the overestimated Gassmann-modeled fluid effect. The results of the revised method are independent of type of clay presence and associated effective porosity. Moreover, the corrected FRM results from the revised Gassmann method shows good agreement with rock physical interpretation of shaly sandstone reservoirs.

Integration and Interpretation of Aeromagnetic, 3D Seismic and Well Logs Data in Hydrocarbon Exploration in Niger Delta Basin

As the challenges associated with hydrocarbon exploration rises with upsurge in energy demand, the need to minimize risk associated with hydrocarbon exploration if supply is to keep up with demand.
 In this work, high resolution aeromagnetic, 3D seismic and well-logs data were adopted and integrated to aid in exploration and characterization of reservoirs in ''XYZ'' field in offshore Niger Delta. Fast Fourier Transform Filter using Oasis Montaj software was applied to the Total Magnetic Intensity grid in horizon and fault interpretation also used to produce subsurface structural maps for sedimentary layer thickness estimation. Direct hydrocarbon indicators (bright spots) on the seismic section was shown using seismic signal. Petrel software and wireline log signatures were used to identify hydrocarbon-bearing sands and determine petrophysical parameters such as porosity, hydrocarbon saturation and net thickness.
 The structural maps generated showed: Three major (synthetic) faults dips south and one minor (antithetic) fault dips north in the field; three identified prospective sands (A, B, C) were delineated. Possible presence of oil accumulation was indicated by the combined Neutron-Density log response. The range of values of effective porosity, hydrocarbon saturation and net thickness were 18-22%, 34-58% and 19.1-28.1 m, respectively. 
 This study established that integration of magnetic, 3D seismic and well-log data are desirable innovative techniques to better understand and analyze subsurface for hydrocarbon potential and exploration.

Oil and Gas Reservoir Characterization; A Case Study of Agbada Field

This study on reservoir characterization was conducted using seismic data and well logs. The aim was to characterize the petrophysical properties and structural element in the field for hydrocarbon volume estimation and determination of infill well locations. Three reservoirs were identified (J100, K100, L100) at shallow, middle and deep depths and correlated across the field using gamma ray log. Petrophysical characterization revealed porosity ranges from 25 to 27% in J100 reservoir, 16% to 27% in K100 reservoir and 11 and 18% in L100 reservoir. This shows good to very good porosity values for reservoir rocks. On average, water saturation is 80%, 68% and 70% in J100, K100, and L100 reservoirs. Net to gross ranged from 24 to 77% in J100, 38 to 82% in K100 and 29 to 75% in L100 and L100 reservoir. Average net to gross revealed that the sands are cleaner with depth. Resistivity and neutron-density logs revealed the reservoirs are oil bearing. Structural characterization of seismic date revealed the presence of synthetic and antithetic faults. Depth structure maps generated revealed closures that are anticlinal and fault supported. Oil water contact super-imposed on the structural maps revealed closures that were oil bearing. Estimation of stock tank oil initially in place revealed 19.511 mmstb, 73.576 mmstb and 19.169 mmstb for J100, K100 and L100 reservoirs respectively, indicate that they can be produced at significant profits. Two infill well placement locations were identified from petrophysical and structural characterization; one at the north central part of J100 reservoir and another at the North-Western part of K100 reservoir.

Shale volume and porosity delineation of coast swamp depobelt in Niger delta region, Nigeria, using well log

Well log data from two wells were evaluated for shale volume, total and effective porosity. Well log data were obtained from gamma ray, neutron-density log, resistivity, sonic and caliper log respectively. This study aimed at evaluating the effect of shale volume, total and effective porosity form two well log data. The results of the analysis depict the presence of sand, sand-shale and shale formations. Hydrocarbon accumulation were found to be high in sand, fair in sand-shale and low in shale, since existence of shale reduces total and effective porosity and water saturation of the reservoir. The thickness of the reservoir ranged from 66 – 248.5ft. The average values of volume of shale, total and effective porosity values ranged from 0.004 – 0.299dec, 0.178 – 0.207dec and 0.154 – 0.194dec. Similarly, the water saturation and permeability ranged from 0.277 – 0.447dec and 36.637 - 7808.519md respectively. These values of total and effective porosity are high in sand, fair in sand-shale and low in shale formations. The results for this study demonstrate: accuracy, applicability of these approaches and enhance the proper evaluation of petrophysical parameters from well log data.

Petrophysical Analysis of Reservoirs Rocks at Mchungwa Well in Block 7 Offshore, Tanzania: Geological Implication on the Reservoir Quality

The present work highlights the results of the study conducted to estimate the petrophyiscal properties of the Mchungwa well with the aim of assessing the quality of reservoirs rocks. A set of well logs data from Mchungwa well were used for the analysis that involved identification of lithology, hydrocarbon and non-hydrocarbon zones and determinations of petrophysical parameters such as shale volume, porosity, permeability, fluid saturation and net pay thickness. This study was able to mark six sandstone zones with their tops and bases. Of the six zones hydrocarbon indication was observed on four zones from which estimation of petrophysical parameters was done to assess the reservoirs quality. The petrophysical parameters across the four reservoirs yield an average shale volume ranging from 0.08 to 0.15 v/v. The porosity ranges from 7% to 23%, indicating a fair to good porosity sandstone, while permeability ranges from 0.01 to 6 mD. The porosity and permeability results suggest that the quality of the sandstone reservoirs identified at Mchungwa well is poor. Fluid types defined in the reservoirs on the basis of neutron-density log signatures and resistivity indicate a mixture of water and gas. However, high water saturation (50% - 100%) indicates that the proportion of void spaces occupied by water is high, thus, indicating low hydrocarbon saturation of 2.4%, 17.9%, 19.2% and 39.3%. Generally the results show that hydrocarbon potentiality at Mchungwa well is extremely low because of small net pay thickness and very low hydrocarbon saturation. This could be attributed to the geology of the surrounding area where low hydrocarbon saturation suggest the presence of non-commercial volumes of either migrant gas or gas generated from the interbedded claystone sediments, which are dominant in the observed well.

Seismic velocity deviation log: An effective method for evaluating spatial distribution of reservoir pore types

Velocity deviation log (VDL) is a synthetic log used to determine pore types in reservoir rocks based on a combination of the sonic log with neutron-density logs. The current study proposes a two step approach to create a map of porosity and pore types by integrating the results of petrographic studies, well logs and seismic data. In the first step, velocity deviation log was created from the combination of the sonic log with the neutron-density log. The results allowed identifying negative, zero and positive deviations based on the created synthetic velocity log. Negative velocity deviations (below −500m/s) indicate connected or interconnected pores and fractures, while positive deviations (above +500m/s) are related to isolated pores. Zero deviations in the range of [−500m/s, +500m/s] are in good agreement with intercrystalline and microporosities. The results of petrographic studies were used to validate the main pore type derived from velocity deviation log. In the next step, velocity deviation log was estimated from seismic data by using a probabilistic neural network model. For this purpose, the inverted acoustic impedance along with the amplitude based seismic attributes were formulated to VDL.The methodology is illustrated by performing a case study from the Hendijan oilfield, northwestern Persian Gulf. The results of this study show that integration of petrographic, well logs and seismic attributes is an instrumental way for understanding the spatial distribution of main reservoir pore types.

Diagenesis of a light, tight-oil chert reservoir at the Ediacaran/Cambrian boundary, Sultanate of Oman

ABSTRACT The Al Shomou Silicilyte Member (Athel Formation) in the South Oman Salt Basin shares many of the characteristics of a light, tight-oil (LTO) reservoir: it is a prolific source rock mature for light oil, it produces light oil from a very tight matrix and reservoir, and hydraulic fracking technology is required to produce the oil. What is intriguing about the Al Shomou Silicilyte, and different from other LTO reservoirs, is its position related to the Precambrian/Cambrian Boundary (PCB) and the fact that it is a ‘laminated chert’ rather than a shale. In an integrated diagenetic study we applied microstructural analyses (SEM, BSE) combined with state-of-the-art stable isotope and trace element analysis of the silicilyte matrix and fractures. Fluid inclusion microthermometry was applied to record the salinity and minimum trapping temperatures. The microstructural investigations reveal a fine lamination of the silicilyte matrix with a mean lamina thickness of ca. 20 μm consisting of predominantly organic matter-rich and finely crystalline quartz-rich layers, respectively. Authigenic, micron-sized idiomorphic quartz crystals are the main matrix components of the silicilyte. Other diagenetic phases are pyrite, apatite, dolomite, magnesite and barite cements. Porosity values based on neutron density logs and core plug data indicate porosity in the silicilyte ranges from less than 2% to almost to 40%. The majority of the pore space in the silicilyte is related to (primary) inter-crystalline pores, with locally important oversized secondary pores. Pore casts of the silica matrix show that pores are extremely irregular in three dimensions, and are generally interconnected by a complex web or meshwork of fine elongate pore throats. Mercury injection capillary data are in line with the microstructural observations suggesting two populations of pore throats, with an effective average modal diameter of 0.4 μm. The acquired geochemical data support the interpretation that the primary source of the silica is the ambient seawater rather than hydrothermal or biogenic. A maximum temperature of ca. 45°C for the formation of microcrystalline quartz in the silicilyte is good evidence that the lithification and crystallization of quartz occurred in the first 5 Ma after deposition. Several phases of brittle fracturing and mineralization occurred in response to salt tectonics during burial. The sequences of fracture-filling mineral phases (dolomite - layered chalcedony – quartz – apatite - magnesite I+II - barite – halite) indicates a complex fluid evolution after silicilyte lithification. Primary, all-liquid fluid inclusions in the fracture-filling quartz are good evidence of growth beginning at low temperatures, i.e. ≤ 50ºC. Continuous precipitation during increasing temperature and burial is documented by primary two-phase fluid inclusions in quartz cements that show brines at 50°C and first hydrocarbons at ca. 70°C. The absolute timing of each mineral phase can be constrained based on U-Pb geochronometry, and basin modelling. Secondary fluid inclusions in quartz, magnesite and barite indicate reactivation of the fracture system after peak burial temperature during the major cooling event, i.e. uplift, between 450 and 310 Ma. A number of first-order trends in porosity and reservoir-quality distribution are observed which are strongly related to the diagenetic and fluid history of the reservoir: the early in-situ generation of hydrocarbons and overpressure development arrests diagenesis and preserves matrix porosity. Chemical compaction by pressure dissolution in the flank areas could be a valid hypothesis to explain the porosity variations in the silicilitye slabs resulting in lower porosity and poorer connectivity on the flanks of the reservoir. Most of the hydrocarbon storage and production comes from intervals characterized by preserved micropores, not hydrocarbon storage in a fracture system. The absence of oil expulsion results in present-day high oil saturations. The main diagenetic modifications of the silicilyte occurred and were completed relatively early in its history, i.e. before 300 Ma. An instrumental factor for preserving matrix porosity is the difficulty for a given slab to evacuate all the fluids (water and hydrocarbons), or in other words, the very good sealing capacity of the salt embedding the slab.

1D radial inversion of multidetector logging-while-drilling Sigma measurements

Sigma measurements are useful in formation evaluation because they can be used to calculate water saturation independently of resistivity. One of the most advantageous features of the logging-while-drilling (LWD) Sigma tool under study is the use of three detectors to measure time decays from which three Sigmas are calculated: one near thermal-neutron detector, one short-spaced gamma-ray detector, and one long-spaced gamma-ray detector. Each detector has a different volume of investigation. Analogous to array resistivity logs, the multidetector Sigma logs, also called multi-depth of investigation Sigma logs, can indicate the presence of invasion and can be used to estimate true formation Sigma. However, the efficacy of the multidetector Sigma interpretation is conditioned by a high-Sigma contrast between invasion and virgin zones. We used a nonlinear gradient-based fast inversion method that uses the measured three-detector time decays and a reference value for invasion-zone Sigma to estimate the radial length of invasion and virgin formation Sigma. Synthetic logs are generated with realistic noise for numerous realizations that are then used to study the stability of the inversion routine and the estimation of error bars. We used a confidence index derived from the multiple-realization study to define the conditions under which the multiple time-decay problem is not stable. The reliability of the Sigma inversion method was verified in a set of test-pit measurements, two synthetic examples, and a field case. Synthetic results indicate that the inversion of multidetector time decays enables the correction of LWD Sigma measurements for invasion effects and improves the calculation of water saturation whenever there is contrast between invasion- and virgin-zone Sigma of more than 5 capture units. Field example results suggest that the inversion can accurately reproduce three-detector time decays honoring invasion effects evidenced in neutron-density logs while managing the presence of noise.

Comparative analysis of sonic and neutron-density logs for porosity determination in the South-eastern Niger Delta Basin, Nigeria

A comparative analysis of porosity values computed from sonic and neutron-density logs obtained from the same well is here presented. The aim is to identify the more reliable logging tool between sonic and neutron-density in the estimation of porosity values in a formation. Two wells from different parts of Niger Delta were logged for Transit times, bulk density and hydrogen index of the formation as a function of depth. The analysis of sonic, density and neutron porosity values shows a conventional trend of decrease in porosity with depth. Sonic porosity values of well A, and well B varies from 1 to 17%, and 27 to 60% respectively while Neutron-Density Porosity values of well A, and well B varies from 24 to 45%, and 21 to 37% respectively. The Coefficient of Variation for sonic porosity data are 56%, and 23%of well A, and well B respectively , similarly the Coefficient of Variation for Neutron-Density porosity data are 15%, and 14% of well A, and well B respectively. Coefficient of variation of Neutron-density log derived porosities is less than sonic log derived porosities; therefore Neutron-density log derived porosity is more reliable tool for porosity data estimation than sonic log derived porosity. Neutron and density logging tool is here recommended for determination of a reliable porosity value of a formation.

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.

Ferry Lake, Rodessa, and Punta Gorda Anhydrite Bed Correlation, Lower Cretaceous, Offshore Eastern Gulf of Mexico: ABSTRACT

ABSTRACT The Lower Cretaceous Ferry Lake and Punta Gorda anhydrite has been used as marker beds throughout the Gulf of Mexico, and divided into 9 individual anhydrite beds traceable from southern Mississippi to southern Florida. The underlying Rodessa Formation has an equally well developed anhydrite section in the offshore Eastern Gulf of Mexico and is divided into 12 basin-wide anhydrite bed groupings. The anhydrites of Ferry Lake and Rodessa Formations are traceable to the anhydrites of the Punta Gorda and Lehigh Acres Formations of South Florida. Anhydrite beds appear to thicken in the central part of the trend interfingering with carbonates of the Lower Cretaceous shelf edge reef. Carbonates and anhydrites may be deposited simultaneously with carbonate patchreefs developing on crests of paleo highs with evaporites precipitating out of a hyper-saline solution on the flanks. Areas where poor anhydrite bed development occurs may indicate areas of patch reefs and, therefore, the best potential for hydrocarbon reservoirs. Individual anhydrite beds have been correlated and color-coded on photocopies of compensated neutron density logs to determine their geographic distribution. Prepared cross sections show some beds to be area wide while others are more restricted. Isopach maps show .the configuration of the basin in which these beds were deposited with the basin's long isopach axis parallel to the reef trend. Anhydrite deposition occurred with evaporation of restricted highstand waters behind reefs that rimmed the shelf edge.

Effect of wellbore condition on wireline and MWD neutron density logs : Allen, D F; Best, D L; Evans, M; Holenka, J M SPE Form EvalV8, N1, March 1993, P50–56

Effect of wellbore condition on wireline and MWD neutron density logs : Allen, D F; Best, D L; Evans, M; Holenka, J M SPE Form EvalV8, N1, March 1993, P50–56

The Effect of Wellbore Condition on Wireline and MWD Neutron Density Logs

Summary The wellbore condition and its corresponding effect on log readings must be assessed and corrected for during log quality control and formation evaluation. Differences arise between measurement-while-drilling (MWD) and wireline neutron density, photoelectric factor (PEF) logs made in the same well because the two systems respond differently to the wellbore environment. Differences also occur because of changes in wellbore condition over time.

Prediction of Pressure Depletion from Wireline and Mud Logs, Golden Trend Field, Garvin County, Oklahoma: ABSTRACT

The Golden Trend, a giant oil field encompassing several overlapping Pennsylvanian stratigraphic traps on the eastern flank of the Anadarko basin, has undergone a resurgence in the 1980s with deeper drilling for pre-Pennsylvanian targets. Approximately 200 new wells in and near the Antioch Southwest, Panther Creek, and Elmore Northeast waterflood units (T2, 3N, R2, 3W) have encountered evidence of undrained reserves in both established and new pay intervals of Pennsylvanian Hart and Gibson sandstones. Although all porous Hart and Gibson sandstones in the study area were originally oil bearing, evaluation of the state of depletion is necessary for planning future recompletions to these reservoirs. In general, wireline and mud logs over intervals with known production histories exhibit characteristics suggestive of pressure depletion, even in areas of old waterfloods. The most consistent parameters correlating to low reservoir pressure are lost circulation, lack of an increase in penetration rate when drilling porous sandstone, excessive gas effect on neutron-density logs, and low methane and total gas levels on the mud logs. The resistivity invasion profile also reflects lower pressure, but is subtle. The SP curve and gas composition on the mud log do not vary substantially as a function of pressure. Visual samplemore » shows are slightly weaker in depleted sandstones, but are less reliable, owing to dependence on reservoir quality and variations between geologists on oral descriptions of show quality.« less

Reservoir Geology of Upper Mississippian St. Louis Limestone, South Mouser Field, Texas County, Oklahoma: ABSTRACT

Five porosity zones in the upper 80 ft (24.4 m) of the St. Louis Limestone have a cumulative production of over 1 million bbl of oil since St. Louis production was discovered at South Mouser field, Texas County, Oklahoma, in April 1983. Porosity in the cored St. Louis Limestone includes primary intergranular, leached grain, and minor vuggy, intragranular, and fracture. Within the five porosity zones, core porosity generally ranges from 6 to 14% and permeability from 1 to 100 md. Porosity development and cementation reflect, for the most part, meteoric diagenesis. Deposition and diagenesis of the upper 100 + ft (30.5 + m) of the St. Louis Limestone were markedly influenced by a local St. Louis paleohigh in approximately the same location as the present structural high at South Mouser field. Cementation, compaction, and a significant amount of ineffective moldic porosity in the cored interval of the St. Louis Limestone result in increased pore system tortuosity. This indicates that an m value greater than 2.0 may be appropriate in S/sub W/ calculations. Additionally, in one porosity zone, ooids contain microporosity visible in SEM study. This porosity may hold irreducible water affecting S/sub W/ calculations made from wireline logs and resultingmore » in an inaccurate assessment of the zone's ability to produce hydrocarbons. Two distinct oil-water contacts occur in the upper St. Louis Limestone at South Mouser. The corresponding reservoirs are separated by a low porosity and permeability layer seen in core and correlated across the field using neutron-density logs.« less

Origin and Geometry of Red River Dolomite Reservoirs, Western Williston Basin

Remarkably uniform distribution of limestone, laminated dolomite, and anhydrite as determined from compensated neutron-density logs suggests that the entire Ordovician Red River Formation of the central Williston basin was deposited in subtidal brining-upward sequences. Study of cores and thin sections verifies this interpretation and reveals that the Red River B and C zones consist of, from bottom to top: (1) highly burrowed locally dolomitized fossiliferous wackestones and packstones, (2) laminated to evenly bedded unfossiliferous mudstones (dolomitized in many wells), and (3) bedded anhydrite. No evidence of subaerial exposure was observed in these rocks units. Dolomitization in the Red River C zone is highly localized. An empirical study of dolomite distribution using data from well logs reveals the presence of dozens of pods of dolomite immediately beneath the C anhydrite. The pods are up to 200 ft (60 m) thick and 1 mi (1.6 km) in diameter and consist of concentered lenses of (1) tight (locally anhydritic) cryptocrystalline dolomite up to 40 ft (12.2 m) thick and 3,300 ft (1,000 m) in diameter, (2) fine to medium-grained porous dolomite that forms the reservoirs, and (3), still farther from the cryptocrystalline dolomite, relatively tight partly dolomitized limestones. These dolomite pods formed by the subtidal downward migration of magnesium-rich brines. The brines formed during or immediately after precipitation of the subtidal anhydrite (probably originally gypsum). Brine migration was localized by holes in the anhydrite and/or upwelling compaction water from the sediments beneath the anhydrite. The holes probably formed by fracturing, minor faulting, or expulsion of water during compaction. Where the magnesium-rich brines first entered the carbonate sediments, they formed cryptocrystalline dolomite but as they migrated away from the holes and lost their potency, they produced porous dolomite (the nature of which was partly controlled by the host sediment) and, still farther away, partly dolomitized limestones. Because certain layers of the C zone carbonates were quite permeable to the dolomitizing brines, highly irregular reservoirs characterized by interfingering limestones and dolomites formed. Several oil fields in the western Williston basin could have been found through application of this model and others could be more efficiently developed.

Origin of Dolomite, Red River Formation, Richland County, Montana: ABSTRACT

Distribution of limestone, dolomite, and anhydrite as determined from compensated neutron-density logs and core studies of the Ordovician Red River Formation in Richland County indicates that: (1) virtually all deposition, including the B and zone anhydrites, occurred subtidally (contrary to previous interpretations invoking localized tidal flats on paleo-highs); (2) various rock units such as the anhydrites and B and laminated zones have remarkable uniformity and lateral continuity over many tens of miles; and (3) dolomitization occurred in subtidal stromatolites, by primary precipitation, or by gravitational seepage of Mg-rich brines into normal marine subtidal carbonates. The lateral persistence of the A and B zone dolomites indicates they formed mainly by primar precipitation and/or dolomitization of subtidal stromatolites whereas the localized replacement dolomites of the and D zones formed by gravitational seepage of dense brines. End_Page 595------------------------------ The zone dolomite of the Red River is the major oil-producing zone in Richland County. This dolomite occurs immediately beneath the C zone anhydrite as concentrated lenses of: (1) tight cryptocrystalline anhydritic dolomite, (2) porous fine to very fine-grained dolomite, and (3) relatively tight partly dolomitized limestone. The dolomitized lenses are typically one to two km in diameter and up to 50 m thick. They apparently formed beneath holes in the anhydrite through which dense Mg-rich brines (formed during precipitation of the subtidal anhydrite) seeped. These holes formed almost randomly, probably by hydraulic fracturing as interstitial waters from compacting sediments beneath the anhydrite escaped upward, but minor faulting may have created more linear holes locally. /P> The D zone dolomite along the eastern edge of Richland County also formed by gravitational seepage, but the absence of a D zone anhydrite allowed for relatively laterally persistent dolomitization. Distribution of D zone dolomite was controlled mainly by paleo-topography of the basin floor; the brines filled in lows whereas dolomitization was minor or nonexistent over paleo-highs. End_of_Article - Last_Page 596------------