Shale Hydrocarbon Potential Research Articles

Fracability Modeling in Shale Hydrocarbon Development Based on Geomechanical Analysis of Well Log and Mineralogy Analysis of Drill Cuttings: A Case Study of the Lower Baong Fm and the Belumai Fm of the NSB-001 Well in the North Sumatra Basin, Indonesia

Abstract The North Sumatra Basin, Indonesia has a very large shale hydrocarbon potential, especially from the Lower Baong Formation and the Belumai Formation. The Belumai and Lower Baong Formations were deposited in the Early Miocene - Middle Miocene, in transgression conditions, when the North Sumatra Basin was in the regional sagging phase. These conditions greatly affect the facies and diagenetic changes of quartz, smectite and kaolinite minerals in rock fracability. The main problem in producing shale hydrocarbons is the very low permeability of unconventional-shale-reservoirs, so that at the production stage of shale hydrocarbon, a fracability model is needed as a basis for planning hydraulic fracking, thus the fractures are connected to each other and can flow the hydrocarbon fluid optimally. From the results of previous studies, it was shown that the shale hydrocarbon fracability value was controlled by lithofacies, and correlated with rock brittleness, brittle mineral content, clay content, and compressive strength. The fracability model is used to determine fracable zone intervals as a candidate for hydraulic fracking, by using geomechanical analysis of well log data and mineralogy analysis of drill cuttings data from the NSB-001 well as a case study. Based on the correlation results of lithology (Mud Log), mineralogy analysis, MBT, and TOC (Drill Cuttings), the sweetpot fracable window (fracable zone interval) can be determined, which is correlated with the presence of fracture barrier.

Effective machine learning identification of TOC-rich zones in the Eagle Ford Shale

Successful hydrocarbon production in the Eagle Ford relies on technological advances such as directional geosteering, horizontal drilling, and hydraulic fracturing, as well as the identification and delineation of organic-rich intervals and fracture zones. Total organic carbon (TOC) is an excellent indicator for the organic richness and the hydrocarbon potential of shale in unconventional reservoirs; however, common methods for TOC estimation have many underlying assumptions and rely on empirical formulas. It is useful to develop a robust data-driven approach that could be used to reliably identify TOC-rich zones in unconventional plays such as the Eagle Ford. Using gamma-ray, deep resistivity, and sonic wireline well log data from La Salle County, South Texas, we generate a layer unit database and label the layer units using core measured TOC values. We apply a data-driven binary support vector machine (SVM) machine learning approach to identify TOC-rich zones within the Eagle Ford. We evaluate the performance of the SVM classifier and obtain F1 scores ranging from 97.4% to 99.4%. The methodology successfully identifies TOC-rich zones that match with geological observations, the ΔlogR method, and independently obtained core TOC measurements. We demonstrate the successful cross-well application of the methodology within the Eagle Ford Play Area and also demonstrate the successful cross-basin application of the methodology using data from the Barnett Shale Formation, Fort Worth Basin, North Texas, and the Duvernay Shale Formation of the West Canadian Sedimentary Basin, Canada.

Predicting reservoir quality in the Bakken Formation, North Dakota, using petrophysics and 3C seismic data

Combining rock-property analysis with multicomponent seismic imaging can be an effective approach for reservoir quality prediction in the Bakken Formation, North Dakota. The hydrocarbon potential of shale is indicated on well logs by low density, high gamma-ray response, low compressional-wave (P-wave) and shear-wave (S-wave) velocities, and high neutron porosity. We have recognized the shale intervals by cross plotting sonic velocities versus density. Intervals with total organic carbon (TOC) content higher than 10 wt% deviate from lower TOC regions in the density domain and exhibit slightly lower velocities and densities (<2.30 g/cm3). We consider TOC to be the principal factor affecting changes in the density and P- and S-wave velocities in the Bakken shales, where VP/ VS ranges between 1.65 and 1.75. We generate the synthetic seismic data using an anisotropic version of the Zoeppritz equations, including estimated Thomsen’s parameters. For the tops of the Upper and Lower Bakken, the amplitude shows a negative intercept and a positive gradient, which corresponds to an amplitude variation with offset of class IV. The P-impedance error decreases by 14% when incorporating the converted-wave information in the inversion process. A statistical approach using multiattribute analysis and neural networks delimits the zones of interest in terms of P-impedance, density, TOC content, and brittleness. The inverted and predicted results show reasonable correlations with the original well logs. The integration of well log analysis, rock physics, seismic modeling, constrained inversions, and statistical predictions contributes to identifying the areas of highest reservoir quality within the Bakken Formation.

Evaluation of shale hydrocarbon potential in upper Talang Akar formation based on laboratory geochemical data analysis and Total Organic Carbon (TOC) modelling

In shale hydrocarbon exploration, shale acts as the source rock and reservoir rock. This study aims to evaluate the potentional of shale hydrocarbons based on the laboratory geochemical data and TOC (Total Organic Carbon) modelling. Evaluation of shale hydrocarbons in sthe study field was carried out on two wells, X-1 and X-3 wells with a target in the upper part of Talang Akar formation as a source rock. Geochemical data is needed for evaluating the quality of the source rock by looking at the total organic carbon content, the maturity, and the hydrocarbon produced by the source rock. Analysis of the laboratory geochemical data resulted that the shale of upper Talang Akar formation had enough potential and mature organic material and also will generate the hydrocarbon in oil form. One of the main parameters for the success of shale hydrocarbons exploration is to know the amount of organic material of the source rock. TOC obtained from laboratory geochemical data is discrete data. Therefore, TOC modelling is carried out to obtain prediction of continuous TOC in upper Talang Akar formation in both wells. This prediction uses three different methods, those are Passey, multiple linear regression, and neural network. Based on those three methods, neural network produces the best data. The correlation obtained from X-1 well and X-3 well using neural network method are 0.96 and 0.84 respectively.

Improved Kerogen Models for Determining Thermal Maturity and Hydrocarbon Potential of Shale

Kerogen is the insoluble component of organic-rich shales that controls the type and amount of hydrocarbons generated in conventional and unconventional reservoirs. Significant progress has recently been made in developing structural models of kerogen. However, there is still a large gap in understanding the evolution of the molecular components of kerogen with thermal maturation and their hydrocarbon (HC) generative potential. Here, we determine the variations in different molecular fragments of kerogen from a Marcellus Shale maturity series (with VRo ranging from 0.8 to 3) using quantitative 13C MultiCP/MAS NMR and MultiCP NMR/DD (dipolar dephasing). These molecular variations provide insight into the (1) evolution of the molecular structure of kerogen with increasing thermal maturity and, (2) the primary molecular contributors to HC generation. Our results also indicate that old model equations based on structural parameters of kerogen underestimate the thermal maturity and overestimate the HC generation potential of Marcellus Shale samples. This could primarily be due to the fact that the kerogen samples used to reconstruct old models were mostly derived from immature shales (VRo <1) acquired from different basins with varying depositional environments. We utilized the kerogen molecular parameters determined from the Marcellus maturity series samples to develop improved models for determining thermal maturity and HC potential of Marcellus Shale. The models generated in this study could also potentially be applied to other shales of similar maturity range and paleo-depositional environments.

Organic Richness and Organic Matter Quality Studies of Shale Gas Reservoir in South Sumatra Basin, Indonesia

Talang Akar Formation is a proven hydrocarbon source rock in South Sumatra basin. The formation contains dominant shale at the top, with some sandstone interbeds. Whereas it contains coarse to very coarse sandstone beds at the bottom. The lower sandstone unit also contains carbonaceous shale and some coal seams. The geochemical analysis is important to identify a source rock quality in shale gas. The quality of source rock is determined by richness of the source rock and type of kerogen. 37 samples were collected from well cuttings in JML-1 and JML-2 wells. Samples we are received into the laboratories in the form of well site canned ditch cuttings, bagged ditch cuttings in various stages of preparation from wet, unwashed to dried, washed; sidewall cores, conventional cores, outcrop samples. The richness of a source rock can be defined by the content of organic carbon which is measured as total organic carbon (TOC). Based on geochemical result of analysis, quantity of shale hydrocarbon potential is indicated by the TOC value of 0.52 wt% - 6.12 wt% (fair to excellent criteria), with average of shale thickness more than 50 m. Tmax is an indication of the maturation stage of organic material and Hydrogen Index (HI) is a parameter used to explain the origin of organic material. HI versus Tmax crossplot was analysed for kerogen type determination and presence of type II/III kerogen was identified. This study concludes that the source rock contains abundant humic organic matter that was deposited in a transitional (Fluvio-deltaic) to marginal marine environment under oxic conditions.

Investigation of Oil Potential in Saline Lacustrine Shale: A Case Study of the Middle Permian Pingdiquan Shale (Lucaogou Equivalent) in the Junggar Basin, Northwest China

The Pingdiquan shale (Lucaogou equivalent) is a typical saline lacustrine deposit in China and is one of the most significant petroleum source strata for the oil and natural gas fields in the Junggar Basin in northwestern China, which is widely acknowledged to have a large shale hydrocarbon potential. This article characterizes the Pingdiquan shale in the eastern Junggar Basin from the geochemical and geological perspectives, describes its oil potential, and compares the results with those from freshwater lacustrine shales. The Pingdiquan shale is highly heterogeneous in its mineral composition, with a big variation in each composition compared to that of freshwater lacustrine shales. The Pingdiquan shale can generally be classified into clastic shale and dolomite shale, where the clastic shale is distributed across the eastern Junggar Basin and thins from north to south, whereas the dolomite shale is developed only in the Jimusaer Sag and at the foot of the Kelameili Mountains. The Pingdiquan shale (both the clastic shale and dolomite shale) has a good petroleum potential and primarily consists of types II and III organic matter with thermal maturity ranging from early to late mature. The oil content (S1) of clastic shale and dolomite shale ranges from 0.01 to 4.96 mg/g and 0.02 to 3.23 mg/g, respectively. The oil content and oil saturation index (OSI) of the Pingdiquan shale reach a maximum value at the early to peak mature zone (Tmax of 445–450 °C). Similar trends can be observed in some typical freshwater lacustrine shales. In the Pingdiquan Formation, the dolomite shale has a higher total organic carbon content and genetic potential (S1 + S2) than the clastic shale; however, its oil content and OSI are lower than those of the clastic shale, as is its production index (PI). The results of one-dimensional basin modeling show that the dolomite shale and clastic shale have had almost the same petroleum transformation ratio values throughout geological history. However, the permeability of dolomite shale is orders of magnitude larger, which allows for more petroleum to be expelled from source rocks. In addition, positive correlations between specific surface areas and OSI and clay content are observed, indicating that high clay content also assists in maintaining the petroleum within the rocks. Therefore, less oil can be retained within dolomite shale than in clastic shale.

Shale Hydrocarbon Potential of Brown Shale, Central Sumatera Basin Based on Seismic and Well Data Analysis

The development of unconventional shale hydrocarbon is really depending on integrating approach of wide range disciplines. The integrated approach for analysing organic-rich shale reservoirs involves calibration of core and well-log data, building petrophysical and rock-physics models, and finally characterizing the key reservoir parameters (TOC, porosity, and natural fractures) and mechanical properties evaluation from seismic data. In this research, integrated approach of geochemical, geomechanical, mineralogy, petrophysical, and geophysical analysis are carried out in Brown Shale, Central Sumatera Basin. Total Organic Carbon (TOC), maturity, and brittleness index are the main parameters used in this study to analyse the shale hydrocarbon potential. The result of geochemical analysis shows that the maturity level of shale in the interest zone in oil window, which means it can generate shale oil in early mature phase at depth of 6400 ft. Quantity of shale hydrocarbon potential is indicated by the TOC value of 0.5-1.2 wt. % (fair to good), with average of shale thickness for over 50 ft. The result of geomechanical analysis shows that brittleness index of interest zone for over 0.48 and rock strength below 10000 Psi.

Hydrocarbon potential of shale and classification and evaluation criteria of shale oil from the Williston Basin

Hydrocarbon potential of shale and classification and evaluation criteria of shale oil from the Williston Basin

EL-NAKHEIL OIL SHALE: MATERIAL CHARACTERIZATION AND EFFECT OF ACID LEACHING

The ever increasing demand for energy and the progressive depletion of crude oil resources, have renewed interest in oil shale as an alternative fuel resource. Weathered oil shale samples were assembled from El-Nakheil phosphate mine in Quseir area, Eastern desert, Egypt. The oil shale samples were prepared and analyzed by XRD (X-ray diffraction), XRF (X-ray flourescence spectrometry), and optical microscopic techniques. Rock-Eval pyrolysis and total organic carbon were used to study shale hydrocarbon potential. A leaching procedure using inorganic and organic acids was used to selectively dissolve the oil shale associated ash forming minerals. XRD results showed that calcite is the dominant carbonate mineral, whereas primary silicate minerals are quartz and montmorillonite. SEM (Scanning Electron Microscopy) observations indicated that the organic matter is dispersed throughout the rock matrix. The acid soluble fraction upon leaching was determined to be 37.59 and 42.74 wt% by using 5% HCl and 10% HCl, respectively. The TOC has been increased from 20.78 to 29.88 and 34.09 wt% by using 5% HCl and 10% HCl, respectively.