Gamma Ray Log Response Research Articles

Emplacement dynamics of a complex thick mafic intrusion revealed by borehole image log facies analyses: Implications for fluid migration in the Parnaíba Basin petroleum system, Brazil

Sill intrusions may play a significant role in the development of petroleum systems in sedimentary basins by promoting maturation of source rocks, influencing fluid migration and acting as reservoirs, traps, and seals for hydrocarbon accumulations. Within this study, we present a novel approach to interpreting geophysical borehole data for a ca. 174 m thick sill from the Parnaíba Basin revealing new insights into both the emplacement mechanisms and impacts of the sill on hydrocarbon migration and trapping. High-resolution ultrasonic and microresistivity borehole image logs were integrated with conventional log data, petrography of eight side wall cores and total gas data recorded during drilling. The petrographic analysis revealed finer crystalline dolerite at the top and bottom layers of the sill while the upper central portion revealed coarser crystalline gabbroic facies, associated with anomalies in gamma ray, neutron porosity, sonic and geochemical log responses. From borehole image logs we interpreted key facies units including massive, fractured, cooling jointed and layered dolerite along with clear evidence for layers containing diverse inclusions interpreted as enclave structures. The integration and correlation of these data with analogue studies allowed the interpretation of gradational cooling with magmatic differentiation, partially melted host rock linked to sulphide production and organic matter maturation, mafic microgranular enclaves related to mingling processes of magma recharge, banding layers related to cumulate zones, and intense cooling fractures in the central sill body. An interval of ca. 44 m at the top of the sill with notably less jointing appears to be responsible for sealing the gas underneath, whilst the fractured central portion of the sill has enabled gas migration evidenced by increased gas signatures. In addition, this work also reveals for the first-time image log evidence for magma mingling and indications of assimilation and anatexis processes within the Parnaíba Basin. This study has important implications for improving the understanding of emplacement mechanisms of thick parallel layer intrusions and their implications for fluid flow in sedimentary basins worldwide.

Identification of Hydrocarbon Zones and Chimneys Using Seismic Attributes Analysis at Woda Oil Field, Western Offshore Niger Delta

This research investigated hydrocarbon zones and chimneys using seismic attributes analysis in Woda Oil Field, Western offshore Niger Delta. Seismic attributes are powerful tools in monitoring and predicting hydrocarbon zones. Detailed application of seismic attributes on the Woda seismic data aided in the extraction of important information about the geologic features on seismic profiles. Materials used in this research include well logs, seismic data and 3D Post Stack Depth Migration (PSDM) seismic volume. Methods used were seismic attribute analysis and well log interpretation. The reservoirs of interest were identified and analyzed using well log data based on gamma ray, resistivity, and Vp sonic log response. Seismic attributes such as chaos, root mean square velocity, similarity and reflection intensity were quality controlled, enhanced, and generated which assisted in identifying chimneys and hydrocarbon zones. The majority of the chimneys in this research may have nucleated in the lower part of the faulting system below the partially permeable portion of the fault planes and across a regional partially permeable barrier as revealed by thin fault likelihood attribute. Gas expulsion along the lower portion of the complex faulting system perhaps, may have preconfigured the spatial organization of the chimneys. Pockmarks formation above the chimneys as revealed by the sweetness attribute may have inherited the same linear planiform geometry, and both structures recorded the timing of hydrocarbon zones and gas expulsion within the Woda Oil Field.

Enhancing Characterization of Reservoirs Within the Niger Delta Basin Using Integration of Seismic and Well Logs

This research utilized well logs and seismic to unravel the reservoir architecture of a field within the offshore depolbelt of Niger Delta. Gamma ray and resistivity log responses were used for lithology and hydrocarbon reservoirs identifications. The principle of similarity in log signatures was used for correlation across the three studied wells. Pertinent reservoir parameters such as shale volume, effective porosity, permeability, hydrocarbon saturation and water saturation were calculated using well-established equations consistent with the geology. Seismic structural interpretation that will give insight to deformation of the field involves the identification and mapping of faults and horizons from seismic sections. By integrating information from seismic and wells, 3D geological modelling was done using geostatistical methods of Sequential Gaussian Simulation and Indicator. The general stratigraphy of the studied field comprises of intercalation of sands and shales which is typical of Agbada formation. Three reservoirs designated as AA, BB and CC were identified and mapped. Only reservoir CC was laterally continuous across the three wells. Reservoir AA has average shale volume of 13%, effective porosity 26%, hydrocarbon saturation 46% and permeability 1328 mD. Reservoir BB has shale volume of 10%, effective porosity 28%, hydrocarbon saturation 43% and permeability 1616 mD. Reservoir CC has shale volume of 21%, effective porosity 20%, hydrocarbon saturation 89% and permeability 580 mD. Twenty faults comprising of both major and minor faults were mapped. The faults mapped were majorly normal faults. The result of the seismic structural interpretation shows that the probable structures harboring oil and gas are a combination of four-way closure and fault assisted anticlinal structures. The modelling of facies and petrophysical parameters into maps aided the understanding of parameter’s influence on oil and gas production. Reservoir CC has oil and gas in commercial quantities with 2520 MMcf and 622Mbbls respectively. The result shows the reservoir has high performance system and is therefore recommended for development and production. The resulting models will aid placement of production wells and monitoring of future performance of the reservoirs.

Petrophysical Properties and Digenetic Evolution of Shuaiba Formation in Nasiriyah Oil Field, Southern Iraq

Shuaiba Formation is a carbonate succession deposited within Aptian Sequences. This research deals with the petrophysical and reservoir characterizations characteristics of the interval of interest in five wells of the Nasiriyah oil field. The petrophysical properties were determined by using different types of well logs, such as electric logs (LLS, LLD, MFSL), porosity logs (neutron, density, sonic), as well as gamma ray log. The studied sequence was mostly affected by dolomitization, which changed the lithology of the formation to dolostone and enhanced the secondary porosity that replaced the primary porosity. Depending on gamma ray log response and the shale volume, the formation is classified into three zones. These zones are A, B, and C, each can be split into three rock intervals in respect to the bulk porosity measurements. The resulted porosity intervals are: (I) High to medium effective porosity, (II) High to medium inactive porosity, and (III) Low or non-porosity intervals. In relevance to porosity, resistivity, and water saturation points of view, there are two main reservoir horizon intervals within Shuaiba Formation. Both horizons appear in the middle part of the formation, being located within the wells Ns-1, 2, and 3. These intervals are attributed to high to medium effective porosity, low shale content, and high values of the deep resistivity logs. The second horizon appears clearly in Ns-2 well only.

Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

Lithology and reservoir properties of the Delaware Mountain Group of the Delaware Basin and implications for saltwater disposal and induced seismicity

ABSTRACTDeepwater siliciclastic deposits of the Delaware Mountain Group (DMG) in the Delaware Basin (DB) are the primary interval for disposal of hydraulic fracturing flowback and produced water from unconventional oil production. Understanding the storage capacity of the DMG is critical in mitigating potential risks such as induced seismicity, water encroachment on production, and drilling hazards, particularly with likely development scenarios and expected volumes of produced water. Here we present a basin-wide geologic characterization of the DMG of the Delaware Basin. The stratigraphic architecture, lithology, and fluid-flow properties including porosity, permeability, amalgamation ratios, and pore volumes, are interpreted and mapped. Lithologies are predicted using gamma-ray and resistivity log responses calibrated to basinal DMG cores and outcrop models. Sandstones exhibit the highest porosity and permeability, and sand depocenters migrate clockwise and prograde basinward throughout Guadalupian time. Permeability is highest at the top of the Cherry and Bell Canyon formations of the DMG, reaching tens to hundreds of millidarcies in porous sandstones. Porous and permeable sandstones are fully amalgamated at the bed scale, but at the channel scale, most sandstones are separated by low-permeability siltstones or carbonates where net sandstone is less than 30%. This geologic characterization can be used to assess the regional storage capacity of the DMG and as input for dynamic fluid-flow models to address pore-pressure evolution, zonal containment, and induced seismicity.

Correlation and sequence stratigraphic interpretation of the lithostratigraphic Snake Cave Interval: Implications for hydrocarbon reservoir prospectivity between the southeast Blantyre and northwestern Neckarboo Sub-basins, Darling Basin, southeastern Australia

Correlation and sequence stratigraphic interpretation was conducted on the upper Lower through upper Middle Devonian sandstones of the Snake Cave Interval succession between the southeast Blantyre and northwestern Neckarboo sub-basins across the central Darling Basin. This article necessitated the definition and use of many sedimentary lithotypes related to different facies associations and depositional environment criteria for the purpose of establishing the sequence stratigraphy to aid hydrocarbon exploration of the studied areas. The data set used a combination of wireline logs, core/cutting data and analysis of the paleo-environments of sedimentary facies from three wells. The sedimentological analysis showed that the Snake Cave Interval section presents three different facies associations, which are visible in both vertical and lateral successions, and are characterised as: meandering and braided fluvial facies associations with minor fluvio-shallow lacustrine complex facies associations. The Snake Cave Interval section in the studied areas is consistently defined by six third-order depositional sequences informally named SCS1, SCS2, SCS3, SCS4, SCS5 and SCS6 in the Nyngynderry-1 and Mount Emu-1 exploration wells, and the Kewell East-1 stratigraphic well. All the stratal patterns in the internal sequence stratigraphic units are asymmetric and marked by lowstand, transgressive and highstand systems tracts separated by sequence boundaries, maximum flooding surfaces and transgression surfaces with unique gamma-ray log response characteristics calibrated by particular lithologic aspects. These are all incorporated within the sequence stratigraphic approach to hydrocarbon reservoir prediction. The stratigraphic architecture of the third-order depositional sequences presented here in our study has implications for the hydrocarbon potential of sandstone reservoirs in the southeastern Darling Basin including the Snake Cave Interval succession targets.

Seismic characterization and origin of clinoforms in lacustrine depositional environments: a case study from the Cretaceous of the South Atlantic

Abstract The lacustrine Itapema Formation in the Santos Basin locally comprises 10 2 m thick clinoforms identified seismically and corroborated by several well penetrations. Individual clinoforms, as proven by well penetrations, are composed of 10 2 m thick successions of basinward-dipping molluscan grainstones and rudstones. Manual dip picking of borehole images shows upward-increasing dips consistent with seismic geometries and a predominance of longshore sediment transport. Clinoforms are bound at their top and base by strata with significantly lower dips recognizable on both seismic and borehole images. Elevated gamma-ray log responses together with sidewall core samples indicate that these intervals correspond to more argillaceous facies which are interpreted as lake flooding events. While the existence of bona fide clinoforms is demonstrated by a range of subsurface data, their precise origin remains enigmatic. The majority of the bivalve genera that make up the grain-supported carbonates appear to be infaunal or semi-infaunal. As such the clinoforms represent large bars produced through the re-working of bivalves from lower-energy depositional environments by shore-parallel currents.

Seismo-Structural Interpretation and Petrophysical Evaluation of Ugwu-Field, Coastal Swamp Depositional Belt of the Niger Delta Basin

Structural interpretation of 3-D seismic data and well log have been applied to unravel hydrocarbon entrapment pattern and petrophysical parameters of X-field within the coastal swamp region of the Niger Delta.. Four reservoir intervals (A, B, C and D) delineated as (W-026, 032, 042 and 048) using gamma ray and resistivity log response. Structural interpretation for inline 5158 revealed four horizons (A, B, C and D) and eight (8) faults labelled (F1, F2, F12, F13, F21, F22, F23, and F24) were mapped. It was observed that the hanging wall block due to reverse drag or rollover anticline slided over fault F12 and created fault F2, thereby creating subsidence where sediments can be deposited. Therefore, faults F2 and F12 created rollover structures which cuts across the entire four reservoirs and invaluably responsible for trapping of hydrocarbon in the field. RMS map developed for horizons ‘A’ and ‘B’ revealed high amplitude anomalies, while variance attribute for both horizons showed relatively uniform lithology observed from east to west across the study area. While from north-east to south west, variance was observed to increase relatively which indicates different lithology. These trend exposes dipping of the channel fill at both flanks by creating extensive faulting. Results of petrophysical evaluation for reservoirs ‘A’ and ‘B’ across the four wells were analyzed. For reservoir ‘A’, porosity values of 32.8%, 24.8%, 25.9% and 27.1% were obtained for wells W-048, 042, 026 and 032 respectively with an average of 27.65%, while for reservoir ‘B’ porosity values of 26.83%, 26.93%, 25.59% and 27.99% for wells W-048, 042, 026 and 032 were obtained respectively with an average of 26.84%. This porosity values were rated very good to excellent for reservoir ‘A’ and very good for reservoir ‘B’, while Permeability values of the order (K > 1000mD) were obtained for both reservoirs across the four wells and is rated excellent. Hydrocarbon saturation (Shc) across the four wells averages at 68.57% for reservoir ‘A’ and 68.67% for reservoir ‘B’ which is high. Log motifs using gamma ray log for well-026 was integrated with seismic facies to infer on depositional environment of the reservoirs horizons showed a combination of serrated funnel/blocky shape log response and coarsening upward cycles. For reservoirs ‘A’, ‘B’ and ‘C’ the log shape pattern indicates deposition in a fluvial / tidal, channel environment while for reservoir ‘D’ the pattern indicates deposition in deltaic front environment. Isochore maps computed for horizons ‘A’ and ‘B’, shows that horizon ‘A’ is relatively thick and this pattern suggests increased tectonic activities during deposition of reservoir ‘A’ and is an indication that reservoir ‘A’ is a synrift deposit. 
 Keywords: 3-D Seismic interpretation, Faults, Seismostratigraphy, Well log, Seismic Attributes, Petrophysical parameters

IDENTIFIKASI DAN ESTIMASI SUMBER DAYA BATUBARA MENGGUNAKAN METODE POLIGON BERDASARKAN INTEPRETASI DATA LOGGING PADA LAPANGAN ”ADA”, SUMATERA SELATAN

As petroleum reserves depleted, certainly encourage the government to search for new energy sources. Eksploration of coal is the right choice because its potential is so great in Indonesian especially in South Sumatera Province is known have content 37,80% from total resources in Indonesian. Well loggging method is one of geophysics method used to find and estimate coal resources. Advantages of well logging method is able to describe subsurface laterally. The purpose of this study is displaying an overview of subsurface rock layers, determine the direction of distribution by correlating coal seam between wells based on data logging, and to estimate coal resources in the research area. The total area of the author's research is 442.056 m2 has 10 wells. Log data used in this study is gamma ray log dan density log, where coal seams are characterized by gamma ray log response and low log density responses. On the field ”ADA” found four coal seam, that is seam A1 with thickness 8,28 m, seam A2 with thickness 13,62 m, seam B with thickness 18,50, and seam C with thickness 8,84. Direction of coal distribution from South to North with slope angle 5-30º and direction of sincerity from East to West. The author calculates the estimated coal resource using polygon method because this calculates method can be done with a short time and the results are right. Total coal by polygon method of 18.322.653 m3 in tons of 21.987.184–27.483.980 ton while calculations with software rock works 15 amount 18.786.254 m3 in tons of 22.543.505–28.179.381 ton.

English

The gamma ray log has over the years provided the conventional means for shale volume (Vsh) estimation. Knowledge of Vsh is used in the prediction of petrophysical parameters like effective porosity and water saturation, which are the input parameters for the calculation of oil in place. Currently, many studies have been conducted on the Bornu Basin of Nigeria, to access its hydrocarbon potential. Unfortunately, the practice of using best gamma ray log value for the computation of gamma ray index, IGR, and subsequently Vsh estimation incorporates huge uncertainty in the estimated volumes. Uncertainty is best captured when estimates are represented in a possible range rather than single value measurements. To the best of our knowledge, this is the first time shale volume has been estimated from the gamma ray log using sampling techniques. The gamma ray log data of the two upper shaly intervals of the NGAMMAEAST_1 well, which penetrates the Gombe formation of the basin, were utilized for this study. The gamma ray log response of the zone of interest is the uncertain parameter in Vsh estimation. A histogram plot of the uncertain log data was used to assume the probability distribution of the data. In the MATLAB platform, Standard Monte Carlo (MC) and Latin Hypercube sampling techniques were used to model the uncertain log response using random numbers. Possible input log data generated from the distribution of the uncertain log data were used in the linear and non-linear models for shale volume estimation to run a series of simulations to determine the possible range of estimates with their probabilities. The Latin hypercube method has shown to be a quick and accurate alternative method to the standard MC method. The approach presented here sets a guideline for the implementation of a probabilistic approach for the volume of shale estimation. Key words: Shale volume, Monte Carlo, Latin hypercube, sampling techniques, gamma ray log.

WIRELINE LOGGING RESPONSE AND TRUE CORE ANALYSIS OF THE UPPER SHALE MEMBER OF ZUBAIR FORMATION, RUMAILA OILFIELD, SOUTHERN IRAQ

Sedimentary rocks can be defined from others not only by their lithology, structures, fossil content, geometry and sedimentary but furthermore by their general response to the wireline logs. This study involves the determination of the properties of Upper Shale Member of Zubair Formation (Lower Cretaceous) in Rumaila oilfield by using several log interpretation software through wireline logging response of lithology. Many wells were chosen in Rumaila oilfield to know the lithology of Upper Shale Member, in addition to calculating permeability for Rumaila oilfield by using eight wells through Rumaila cross-section. The Gamma Ray log responses of clean sand range between 30 – 40 API, while it decreased in the case of silt and clay cemented sand grain. Sandstones are dominated in the south of Rumaila, this could increase the porosity and permeability of the rocks. While clay and shale are dominated in the north of Rumaila. Log responses don’t give a true representation for formation lithology if comparison with true core lithology by using grain size analysis.

Geophysical strata rating (GSR) as an aid in carbonate reservoir characterisation: an example from the South Pars gas field, Persian Gulf Basin

In this study, the geophysical strata rating (GSR) is calculated from petrophysical data using the equations developed for clastic rocks. The region being investigated is the South Pars gas field in the Persian Gulf Basin, where the Permian–Triassic Dalan and Kangan reservoirs host the largest accumulations of gas in the world. A 3D GSR model is estimated from 3D poststack seismic data by using a probabilistic neural network model. In this study, two methodologies are used to obtain GSR values at the different scales of wireline logs and 3D seismic data.Strong correlations between neural network predictions and actual GSR data at a blind well prove the validity of the intelligent model for estimating GSR. The GSR results are also in good agreement with porosity and elastic moduli of these carbonate rocks. Discrimination between the reservoir and non-reservoir shaly units can easily be obtained by comparing GSR and well logs. Very low GSR values with high gamma ray log responses indicate shaly intervals. These can cause washouts, casing collapse and other related drilling problems. Intervals with low GSR values and low gamma ray log responses indicate the presence of good reservoir units.

CHARACTERIZATION OF THE HYDROCARBON POTENTIAL AND NON-POTENTIAL ZONES USING WAVELET-BASED FRACTAL ANALYSIS

The identification of prospective and dry zone is of major importance from well log data. Truthfulness in the identification of potential zone is a very crucial issue in hydrocarbon exploration. In this line, the problem has received considerable attention and many conventional techniques have been proposed. The purpose of this study is to recognize the hydrocarbon and non-hydrocarbon bearing portion within a reservoir by using the non-conventional technique. The wavelet based fractal analysis (WBFA) has been applied on the wire-line log data in order to obtain the pre-defined hydrocarbon (HC) and non-hydrocarbon (NHC) zones by their self-affine signal nature is demonstrated in this paper. The feasibility of the proposed technique is tested with the help of most commonly used logs, like self-potential, gamma ray, resistivity and porosity log responses. These logs are obtained from the industry to make out several HC and NHC zones of all wells in the study region belonging to the upper Assam basin. The results obtained in this study for a particular log response, where in the case of HC bearing zones, it is found that they are mainly situated in a variety of sandstones lithology which leads to the higher Hurst exponent. Further, the NHC zones found to be analogous to lithology with higher shale content having lower Hurst exponent. The above proposed technique can overcome the chance of miss interpretation in conventional reservoir characterization.

Fractal analysis of logs to characterize the hydrocarbon and non-hydrocarbon zones of Bhogpara oil field, Northeast India

Identification with accuracy of prospective and dry zone from well log data is of prime importance in reservoir or hydrocarbon studies. This issue has greater stake, where in return many conventional methods have been established. The purpose of this study is to recognize the hydrocarbon and non-hydrocarbon bearing portion within a reservoir by using a non-conventional technique. Application of rescaled range (R/S) analysis and wavelet-based fractal analysis (WBFA) on the wire-line log data to obtain the pre-defined hydrocarbon (HC) and non-hydrocarbon (NHC) zones by their fractal nature is demonstrated in this paper. Among these two techniques, the WBFA tool has provided more prolific results. Applicability of the proposed approach is tested with the help of the most commonly used well log data like self-potential, gamma ray, and porosity log responses. These are used in the industry to distinguish several HC and NHC zones of all wells in the study region belonging to the Upper Assam Basin, India. The results are found to be of lower fractal dimension in this study for a particular log response having HC-bearing zones, which are mainly situated in a variety of sandstone lithology. On the other hand, NHC-bearing zones correspond to lithology with higher shale content categorized with higher fractal dimension. Hence, the WBFA technique can overcome the chance of misinterpretation, which is quite possible in the case of conventional reservoir characterization.

Petro physical properties analysis of beani bazar gas field, Bangladesh using wireline log interpretation

The study on analysis of petro physical properties which are done into two well such as BB-1 and BB-2 of Beani Bazar Gas Field using wire line log data. In BB-1, Upper Gas Sand (UGS), Lower Gas Sand (LGS), Sand-1 and Bellow Lower Gas Sand (BLGS) zones and in BB-2, UGS and LGS are identified through high gamma ray log, high resistivity, low neutron and low density log response. The thickness of UGS, LGS, Sand-1, BLGS of BB-1 and UGS, LGS of BB-2 are respectively 47.69m, 14.326m, 17.526m, 17.526m and 26.37m, 21.03m. The Shale volumes of UGS, LGS, Sand-1 and BLGS of BB-1 are respectively 14.87%, 21.58%, 11.69% and 21.28% and UGS and LGS of BB-2 are respectively 17.91% and 29.33%, which are measured through Schlumberger Clavier method. The average porosity of UGS, LGS, Sand-1 and BLGS of BB-1 are respectively 17.55%, 16.60%, 18.07% and 31.10% and UGS and LGS of BB-2 are respectively 13.19% and 11.29%, which are very effective for hydrocarbon prospect by using neutron-density combination method. The average water saturations of UGS, LGS, Sand-1 and BLGS of BB-1 are respectively 24.97%, 23.78%, 80.18% and 19.85% which revised to hydrocarbon saturations as respectively 75.03%, 76.22%, 19.82% and 80.15% and UGS and LGS of BB-2 are respectively 41.20% and 69.50% which revised to hydrocarbon saturations as respectively 58.80% and 30.50% that are followed by Simandoux method. By analysis of petro physical properties of those zones, the UGS and LGS are very effective hydrocarbon bearing zones where production is running at the present time, the Sand-1 zone is water bearing zone. This study impose high important on BLGS. This zone is satisfied all criteria for hydrocarbon prospect. This study recommends that more study is needed for BLGS, and it may be commercially economical viable in a future.

Radioactive Occurrence in Sediments of Cenozoic Age near Bandha Village, Jaisalmer District, Rajasthan

ABSTRACT The radioactivity is dependent on the isotope and their concentration in the mineral such as potassium (K), uranium (U) and thorium (Th). In this paper the presence of a 3 to 5 m thick uranium and thorium bearing sediment of Cenozoic age is reported above Goru Formation of Jaisalmer basin. Gamma ray log response of Well-1 which falls under the study area has marked with very high GR (gamma ray) readings ranging from 350-1488 API coupled with high uranium and thorium content from spectral gamma ray log ranging from 92-178 ppm and 60-80 ppm respectively at the depth of 50 m from ground surface (-110m above MSL). Further studies are required to delineate the lateral thickness variation for mining purpose which may be a radioactive source.

A new method for estimating total organic carbon content from well logs

With the booming exploration and development of unconventional hydrocarbon resources in source rocks, the estimation of total organic carbon (TOC) content from well logs has become increasingly important because of the significance of TOC in the formation evaluation of those resources. In this paper, a new log overlay method is developed to estimate the TOC content of source rocks with excess radioactivity, but containing little or no potassium feldspar. Specifically, on the basis of previous results of log responses of source rocks, it is believed that the natural gamma ray (GR) log responses of source rocks in the applicable conditions are predominantly contributed by clay minerals and organic matter. A practical clay indicator is established to reflect the clay content using density and neutron logs. The indicator is effective not only in nonsource rocks that contain oil or water but also in source rocks. Furthermore, a new method was developed by overlaying the properly scaled clay indicator curve on the GR curve. In nonsource rocks, including clay-rich rocks and reservoirs saturated with oil or water, the two curves overlie each other, whereas a separation between the curves occurs in organic-rich source rocks. The separation between the curves was defined and expressed and can be used to calculate the TOC consecutively after careful calibration with core data. This method has been successfully applied to two shale gas plays with high-maturity kerogen in the Sichuan Basin, China. In addition, a source rock with low-maturity kerogen was used to verify the new method for its effectiveness, reliability, and widespread adaptability.

Identification of formation interfaces by using wavelet and Fourier transforms

The identification of formation interfaces is of prime importance from well log data. The interfaces are not clearly discernible due to the presence of high and low frequency noise in the log response. Accurate bed boundary information is very crucial in hydrocarbon exploration and the problem has received considerable attention and many techniques have been proposed. Frequency spectrum based filtering techniques aids us in interpretation, but usually leads to inaccurate amplification of unwanted components of the log response. Wavelet transform is very effective in denoising the log response and can be carried out to filter low and high frequency components of signal. The use of Fourier and Wavelet transform in denoising the log data for obtaining formation interfaces is demonstrated in this work. The feasibility of the proposed technique is tested so that it can be used in the industry to decipher formation interfaces. The work flow is demonstrated by testing on wells belonging to the Upper Assam Basin, which are self-potential, gamma ray, and resistivity log responses.

Allostratigraphy and paleogeography of the Harmon and Cadotte members of the Peace River Formation (Middle Albian), west-central Alberta and adjacent British Columbia

Abstract The mudstone-dominated Harmon and sandstone-dominated Cadotte members of the Peace River Formation were deposited during the middle Albian in the southern end of a Boreal marine embayment that occupied the foredeep of the Western Canada Foreland Basin. Sandstone of the Cadotte Member represents a shoreface environment and has traditionally been interpreted as the updip equivalent of offshore Harmon mudstone. Allostratigraphic correlation, based on marine flooding surfaces and unconformities shows that the Harmon alloformation can be divided into five regionally-mappable allomembers. Similar erosion surfaces allow the Cadotte alloformation to be divided into three allomembers. The new allostratigraphy shows that the informal Harmon and Cadotte alloformations do not have an interfingering relationship and hence are not genetically related. Harmon and Cadotte allomembers have been mapped over about 100 000 km2, but show no evidence of stratal lap-out or depositional topography; it is concluded that deposition took place on a shallow marine ramp of very low relief. The vertical stacking of Harmon and Cadotte allomembers across the foredeep indicates that rates of accommodation and sediment supply remained in approximate equilibrium throughout deposition of these units. In the far southern and eastern parts of the study area, changing gamma ray log response suggests that marine deposits of both the Harmon and Cadotte alloformations grade laterally into coeval coastal plain deposits that are mapped in outcrop as Gates Formation whereas in subsurface wireline log picks, these rocks are usually included in the Upper Mannville Group. The lateral boundary between offshore mudstone and coeval nearshore muddy sandstone can be mapped within individual Harmon allomembers; the mudstone to sandstone boundary has a lobate to cuspate pattern in plan view, suggesting that, at the southern extremity of the ‘Harmon Sea’ rivers built elongate deltas in a very shallow-water, low wave-energy setting. Lenticular, sharp-based sandstone bodies 17–42 m thick hang from allomember bounding surfaces in both the Harmon and Cadotte alloformations; these sandbodies probably represent paleovalley fills. Valley incision may have been linked to relative sea-level changes that also gave rise to the marine transgressive surfaces that are traceable over the entire study area. In the east, both the Cadotte and Harmon alloformations are completely truncated by a bevelling unconformity at the base of the Paddy and the laterally-contiguous Joli Fou alloformation.