Architecture of the metamorphic Algyő High (SE Pannonian Basin) based on lithological interpretation of natural gamma-ray logs

The Ministry of Economy, Trade and Industry, Japan, drilled the Tokai-oki to Kumano-nada exploratory test wells to obtain data for understanding the occurrence of methane hydrate and estimating the volume of gas stored as methane hydrates in the Nankai Trough, offshore central Japan. In this project, we conducted logging while drilling at 16 sites, coring at four sites, wireline logging at two sites, and long-term monitoring of formation temperature at a single site. Massive or layered methane hydrates within muddy layers were recovered at sites 1 and 2 by drilling with a conventional wireline-core system. The methane-hydrate-bearing sediments in these sites are a combination of clay and silt, which is not commonly considered a favorable host sediment for hydrate formation; however, a significant decrease in core temperature was recorded within intervals of layered hydrates. Pore-space-type hydrates were identified in sand layers from sites 4 and 13 within 82 m (269 ft) of recovered core using a pressure temperature core sampler (PTCS). Sediments within this core are mainly very fine- to fine-grained turbidite sand layers of several centimeters (inches) to 1.5 m (5 ft) in thickness (average of 20–40 cm [8–16 in.]). Core-temperature measurements and the relationship between well-log resistivity and grain-size distribution indicate that methane hydrate is concentrated within layers of coarse-grained sand. We identify five sedimentary facies on the basis of a lithological column created from core and well-log data at sites 4 and 13. Facies analysis indicates that the depositional environment in hydrate-bearing zones at sites 4 and 13 consisted of distributary channels to distal lobes within a submarine-fan system. Shipboard hydrate dissociation tests on PTCS cores reveal that average hydrate saturation in the cored sand layers ranged from 55 to 68%, with the average sediment porosities ranging from 39 to 41%, based on the analysis of both well-log and core measurements.

This paper discusses a method for measuring the porosities of core or outcrop samples using the attenuation of gamma rays. The method has been experimentally validated against porosities measured with Archimedes’ method on a variety of lithologies and over a range of porosities. The method is fast, non-destructive, and can characterize small scale heterogeneities in porosity. The lithology and fluid saturations must be known, however.

Thermal conductivity of sediments from well-logs and its application to determine heat flow density in the Pannonian Basin, Hungary

For the development of methane hydrate (hereafter called ‘hydrate’) as possible future energy resources, the great effort has been paid for developing new seismic methods to delineate hydrate reservoir and its quantification through the first stage of MH21 national project. Not only for reservoir delineation but also for understanding hydrate system (methane generation, migration and accumulation as a hydrate) and geological history of hydrate sediment, we have made a rock mechanical study for hydrate and non-hydrate sediment theoretically and experimentally using the well data and core samples. As a first step in our study, we have tried to calculate the mechanical strength of the methane hydrate-bearing sediment based on the Coulomb-Mohr failure criterion. As a result, the sediment below the methane hydrate-bearing layer is apparently mechanically weaker than methane hydrate-bearing layer. This result is consistent with our knowledge that caliper data shows the weakness of the well-bore wall. As second step, we also measured the mechanical strength of the core samples recovered at Nankai Trough. The measurement was made to the core samples, one of which is under in situ condition and another of which was done after dissociation. As a result, the strength of the hydrate-contained core of high saturation is about 4 times stronger than that of hydrate-dissociated core. This result is completely same as that of calculated strength using the well-logging data and well-logging (caliper) data.

Reservoir hydrocarbon potential of the Miocene Agbada Formation using RMS amplitude map and hydraulic flow unit model, Hatch Field offshore, Niger Delta Basin, Nigeria

The organic-matter content of the Devonian shale of the Appalachian basin is important for assessing the natural-gas resources of these rocks, and patterns of organic-matter distribution convey information on sedimentary processes and depositional environment. In most of the western part of the Appalachian basin the organic-matter content of the Devonian shale can be estimated from gamma-ray wire-line logs using the equation: ϕ0 = (γB − γ)/1.378A, where ϕ0 is the organic-matter content of the shale (fractional volume), γ the gamma-ray intensity (API units), γB the gamma-ray intensity if no organic matter is present (API units), and A the slope of the crossplot of gamma-ray intensity and formation density (API units/(g/cm3)). The quantities A and γB vary regionally and are mapped using data from gamma-ray and formation-density wire-line logs. Organic-matter contents estimated using this equation are compared with organic-matter contents determined from direct laboratory analyses of organic carbon for 74 intervals of varying thickness from 12 widely separated wells. The organic-matter content of these intervals ranges from near zero to about 20% by volume. Excluding the Cleveland Member of the Ohio Shale and the lower part of the Olentangy Shale, the distribution of the differences between volume-percent organic-matter content determined from core samples and estimated from gamma-ray logs has a mean of 0.44% and a standard deviation of 1.98%, which indicates that the accuracy of the gamma-ray method is adequate for most geologic applications. The gamma-ray intensity of the Cleveland Member of the Ohio Shale and the lower part of the Olentangy Shale is anomalously low compared to other Devonian shales of similar richness, so that organic-matter content computed for each of these units from gamma-ray logs is likely to be too low. Wire-line methods for estimating organic-matter content have the advantages of economy, readily available sources of data, and continuous sampling of the vertically heterogenous shale section. The gamma-ray log, in particular, is commonly run in the Devonian shale, its response characteristics are well known, and the cumulative pool of gamma-ray logs forms a large and geographically broad data base. The quantitative computation of organic-matter content from gamma-ray logs should be of practical value in studies of the Appalachian Devonian shale. The general approach described here may also be applicable to other formations with physical and geochemical characteristics similar to the Appalachian Devonian shale.

We develop a new alternative for the joint inversion of well logs to predict the volumetric and zone parameters in hydrocarbon reservoirs. Porosity, water saturation, shale content, kerogen, and matrix volumes are simultaneously estimated with the tool response function constants with a hyperparameter estimation assisted inversion of the total and spectral natural gamma-ray intensity, neutron porosity, and resistivity logs. We treat the zone parameters, i.e., the physical properties of rock matrix constituents, shale, kerogen, and porefluids, as well as some textural parameters, as hyperparameters and estimate them in a metaheuristic inversion procedure for the entire processing interval. The selection of inversion unknowns is based on parameter sensitivity tests, which indicate that the automated estimation of several zone parameters is favorable, and their possible range can also be specified in advance. In the outer loop of the inversion procedure, we use a real-coded genetic algorithm for the prediction of zone parameters, and we update the volumetric parameters in the inner loop in addition to the fixed values of the zone parameters estimated in the previous step. We apply a linearized inversion process in the inner loop, which allows for the quick prediction of volumetric parameters along with their estimation errors from point to point along a borehole. The derived parameters, such as hydrocarbon saturation and total organic content, indicate good agreement with core laboratory data. The significance of the inversion method is that the zone parameters are extracted directly from the wireline logs, which improves the solution of the forward problem and reduces the cost of core sampling and laboratory measurements. In a field study, we demonstrate the feasibility of the inversion method using real well logs collected from a Miocene tight gas formation situated in the Derecske Trough, Pannonian Basin, East Hungary.

2D seismic interpretation of Sawan gas field integrated with petrophysical analysis: A case study from Lower Indus Basin, Pakistan

The mail goal of the current paper is to establish a Multilayer perceptron (MLP) neural network machine for rock permeability prediction from well-logs data. The MLP machine is composed of three layers, an input layer with 05 neurons a hidden layer with five neurons, the output layer is composed with one neuron. Well-logs data to be used as an input are: the natural gamma ray, the bulk density of the rock, the Macro-resistivity, the velocity of the compression wave and the neutron porosity. The output of the machine is the predicted permeability. Well-logs data of a pilot borehole located in the Algerian Sahara are used for the training, where the modified hidden weight optimization (MHWO) algorithm is used. Generalization to a second borehole located in the neighbourhood of the pilot borehole clearly shows that the implanted MLP machine using the MHWO can greatly improve reservoir characterization.KeywordsMLPMHWOpredictionpermeability

Magnetic susceptibility (MS) and natural gamma ray (NGR) were measured on middle Miocene to Cenomanian coastal plain strata from a continuously cored (356 m total depth; 86% recovery) borehole at Ancora, New Jersey (Ocean Drilling Program Leg 174AX). These measurements were integrated with lithologic descriptions and a downhole NGR log. A simple linear model explains most of the variation of the downhole NGR and the core MS as a consequence of the previously described lithologic variation. Spectral NGR at selected levels shows that NGR activity is mostly due to 40K associated with glauconite and mud, sediment components that also tend to give high MS values. Abrupt deviations from the average values of NGR activity and MS determined by the linear model can be interpreted as due to singular lithologies. For example, an anomalous level with high NGR but not a parallel increase in MS was found at the Navesink/Mount Laurel formation contact and can be attributed to high uranium concentration in phosphorite. Most (27 of 33) of the sequence boundaries independently identified at the Ancora site have sufficient lithological contrasts to be expressed in the NGR and/or MS logs.

Summary Workovers and recompletions of old wells, evaluation and monitoring of reservoir behavior during primary, secondary, and ternary recovery, and exploration for bypassed oil in cased wells make the proper selection of cased-hole logs and/or optimal logging suites a necessity. Required information includes the integrity of the cement bond between casing and the formation, lithology identification, porosity, type and distribution of reservoir fluids, formation permeability, and anticipated watercut estimates. These data can be obtained from vitrious log responses, which include natural total and/or spectral gamma ray radioactivity measurements, radiation-type logs (density, neutron), pulsed neutron logs. acoustic measurements, etc. In addition. special time-lapse logging techniques monitor reservoir behavior and state of hydrocarbon depletion, whereas log-inject-log (LIL) techniques enhance the accuracy of residual oil saturation (ROS) estimates. Introduction Cased-hole logging capabilities and associated quantitative interpretation techniques have become very important in several applications, including, cased-hole exploration, completion, workovers. and the monitoring of hydrocarbon reservoirs under primary, secondary, or tertiary recovery schemes. Cased-hole well logging concepts are reviewed which are currently used (1) to explore for bypassed hydrocarbons in abandoned or old workover wells; (2) to work in fresh, brackish, or unknown formation water salinities; (3) to evaluate hydrocarbons in new wells in which openhole logs could not be run, (4) to monitor production behavior and depletion in reservoirs under primary driving mechanisms, breakthrough in waterfloods, chemical and micellar projects, C02, and steam- and fireflood projects; (5) for residual oil saturation based on LIL techniques, etc. Several field case examples and references are presented. Reservoir Characterization Lithology. Natural radioactivity measurements have phyed an important role in wireline logging operations since about 1935. Most of the natural gamma ray logging techniques applied in formation evaluation measure the total and/or individual contribution of gamma rays from potassium, uranium, and thorium series by means of standard gamma ray and/or spectral gamma ray logging. The fact that natural gamma-ray intensities vary as a function of lithology was recognized as early as 1939. Gamma rays are the radiations originating within an atomic nucleus. A nucleus gives off excessive energy (gamma rays) as the result of radioactive decay or an induced nuclear reaction. Radioactive decay consists of the emission or capture of elementary or composite particles with consequent transformations into daughter nuclei characterized by different atomic numbers and, in some cases, by different mass numbers. As early as the 1950's, field tests in boreholes were carried out to study the feasibility of detecting some of these nuclides by gamma ray spectroscopy techniques that identify characteristic gamma rays. Of particular interest are those of potassium and the uranium and thorium series. Both uranium and thorium are characterized by specific decay series. Potassium consists of three isotopes that exhibit masses of 39, 40, and 41 with abundames of 9318, 0.0119, and 6.9%. The only unstable isotope of potassium is the nuclide potassium-40, the major contributor, which emits a single, easily identifiable gamma ray at 1.46 MeV. Hence, in addition to total gamma ray counts, the Spectralog TM measures and records the gamma rays emitted by potassium-40 (40K) at 1.46 MeV, the uranium series nuclide bismuth-214 (214Bi) emanating gamma rays at 1.764 MeV and the thorium series nuclide thallium-208 ( 208Th) emanating gamma rays at 2.614 MeV. These nuclides are of particular interest to the oil industry since, in various amounts, all are found in subsurface formations as constituents of potential reservoir rocks. Table 1 illustrates the distribution of potassium (K, %), uranium (U, ppm), and thorium (Th, ppm) for several formation constituents detrimental to optimal reservoir rock conditions. Application of such spectral gamma ray data may be made either qualitatively or quantitatively. As is extensively documented in logging literature, natural spectral gamma ray logging assists greatly in geological studies (lithology identification, recognition of depositional environment, stratigraphic correlation, source rock evaluation, etc.), complex reservoir rock analysis (heavy minerals, mica, feldspar, glauconite, fractures, silt. etc.), shaliness estimates, in-situ clay typing, cation exchange capacity (CEC) estimates, and radioactivity buildup under dynamic fluid conditions (channeling behind pipe, high-permeability streaks, fractures. caverns, watered-out zones, etc.) and/or around perforations. JPT P. 249^

Summary This paper discusses a new method for predicting continuous logs of effective permeability to oil in sandstone and carbonate formations from well-logging data. This important problem in formation evaluation has remained previously unsolved because the conventional approach used to predict reservoir properties from well-log data relies on simple empirical equations and idealized models of reservoir rocks. The use of such equations and models to predict a complex reservoir property (e.g., effective permeability) can result in an inaccurate representation of the formation. This paper shows that accurate values of effective permeability to oil can be predicted using model-independent mapping functions constructed from Gaussian radial basis functions (RBFs), which can be derived from a laboratory database of measurements on partially saturated core samples. The mapping functions replace the empirical equations used in the conventional approach and are model-independent representations of the database measurements. Once the mapping functions are constructed from the database, there are no adjustable parameters. In this study, mapping functions for sandstones and carbonates were derived from a worldwide database of laboratory measurements made on 79 sandstone and 25 carbonate core samples. The laboratory measurements available on each sample included irreducible water saturation, effective permeability to oil, porosity, and nuclear-magnetic-resonance (NMR) T2 distributions. The mapping functions can be used to predict effective permeability to oil of reservoirs at irreducible water saturation from input measurements of porosity, T2 distribution, irreducible water saturation, and knowledge of rock lithology (e.g., sandstone or carbonate). The methodology for deriving the mapping functions is explained in detail. The mapping functions are applied to the database itself to show the accuracy of the effective-permeability predictions on core samples. The method is also applied to log data from both sandstone and carbonate formations in three wells from different parts of the world. The predicted effective permeabilities to oil are shown to be consistent with oil mobilities measured in the formations by fluid-sampling tools.

Important hydrocarbon accumulations occur in platform carbonates of the Lower Cretaceous Kharaib (Barremian and early Aptian) and Shuaiba (Aptian) formations (upper Thamama Group) of Abu Dhabi. The Kharaib and Lower Shuaiba formations contain three reservoir units separated by three low-porosity and low-permeability dense zones. From base to top, the thickness of the reservoir intervals range from approximately 80, 170, to 55 ft (24, 51, to 16 m), respectively, for the Lower Kharaib, Upper Kharaib, and Lower Shuaiba Reservoir Units. Core and well-log data of a giant oil field of Abu Dhabi, as well as outcrop data from Wadi Rahabah in the Emirate of Ras Al-Khaimah were used to establish a sequence-stratigraphic framework and a lithofacies scheme, applicable to all three reservoir units and the three dense zones. The Lower and Upper Kharaib Reservoir Units, as well as the lower, middle, and upper dense zones are part of the late transgressive sequence set of a second-order supersequence, made up of two third-order composite sequences. The overlying Lower Shuaiba Reservoir Unit belongs to the late transgressive sequence set and the early highstand sequence set of this second-order supersequence and is made up of one third-order composite sequence. The three third-order composite sequences are composed of 19 fourth-order parasequence sets that show predominantly aggradational and progradational stacking patterns, typical of greenhouse cycles. Conventionally, composite sequence boundaries are placed at or near the base of the three dense zones. As an alternative scenario, the possibility that the major composite sequence boundaries actually occur on top of these dense zones is discussed. On the basis of faunal content, texture, sedimentary structures, and lithologic composition, 13 reservoir lithofacies and 8 nonreservoir (dense) lithofacies are identified from core. Similar lithofacies are identified in time-equivalent rock exposures studied in Wadi Rahabah. Depositional environments of reservoir units range from lower ramp to shoal crest to near-back shoal open-platform deposits. Dense zones were deposited in an inner-ramp, restricted shallow-lagoonal setting. Intensively bioturbated wackestone and packstone, and interbedded organic- and siliciclastic-rich limestone, characterize the dense zones. Locally, mud cracks, blackened grains, and rootlets are observed. Outcrop analogs of subsurface reservoirs allow for a detailed investigation of facies architecture and structure of carbonate bodies. Integration of subsurface and outcrop data (e.g., low-angle clinoforms that cannot be seen in core data) leads to more insightful and realistic geological models of subsurface stratigraphy. Geological model realizations based on core, outcrop, well-log, and seismic data constrain fluid flow-simulation models. Results mimic known behavior in analogous producing fields, and the process of going from rock data to simulation provides a useful training tool for reservoir characterization methods and techniques.

The volume of hydrocarbon exists in the reservoir is directly related to the quantity of the hydrocarbon generated and expelled from the source rock. Accurate evaluation of source rock is important for hydrocarbon production planning and subsurface resource prediction. This study evaluates the source rocks of the shale zones within the Kurra Chine Formation using well-logging data and Rock-Eval pyrolysis analysis for Well-6 in the Peshkhabir Oil Field, located at Zakho, Northern Iraq. Comprehensive well logging data of Well-6 in the Peshkhabir Oil Field, and sixteen cutting samples were selected for this study. The result indicates that the total organic carbon wt.% of Well-6 ranges from 0.39 - 1.62 %, classifying the Kurra Chine as a good source rock in the shale zones. The Generation potential ranges from 1.02 – 6.562, additionally confirming the source rock potentiality through wireline logs. The S1 value for most samples ranged between 2.68 – 3.16, indicating favourable hydrocarbon presence and suggesting a good quality source rock. The level of maturity, represented by thermal maturity, ranges between 400 °C – 420 °C for most samples, indicating them as immature to marginally mature. Furthermore, the kerogen types predominately fall under type III, based on the relationship between hydrogen index and thermal maturity.

Seismic data are routinely and effectively used to delineate the structure of a reservoir. However, the use of seismic data in reservoir modeling has been limited. This paper introduces a new approach of incorporating 3-D seismic data in reservoir porosity modeling. This approach employs a stochastic seismic inversion technique to generate the seismic impedance. The inversion technique uses a modified stochastic hillclimbing method. Correlation between porosity and the inverted impedance is established at well locations. The resulting relationship is used to generate 3-D porosity models. The generation of these models involves a stochastic co-simulation of inverted seismic impedance of loc-derived porosity. This modeling technique is applied to the Yacheng 13-1 Gas Field. The results are compared with porosity models generated using well-log data only, as well as with using seismic amplitude and well-log data since a good correlation between seismic amplitude and well log data is also observed after transforming the data into similar scales. The results demonstrate a protocol for early integration of geological and geophysical data in a gas reservoir. This approach will allow easy revision and refinement of the description with additional data, such as new well data or new interpretation of the existing data.