Shale Volume Research Articles

Data analytics and Bayesian Optimised Extreme Gradient Boosting approach to estimate cut-offs from wireline logs for net reservoir and pay classification

Accurate net pay classification is essential in hydrocarbon resource volumetric calculation. However, there is no universal methodology developed for its evaluation hence the existence of many incongruent views on its application since it is data-driven and differs for each reservoir. This research incorporates machine learning and data analytics in predicting net pay, intending to reduce uncertainties associated with the net-pay classification. Log analysis was performed to determine the cut-offs for sonic, neutron, density, and gamma-ray using unsupervised learning and data analytics. The log cut-offs were calculated with petrophysical properties; shale volume, water saturation, permeability, and porosity. A Bayesian Optimised Extreme Gradient Boosting (Bayes Opt-XGBoost) model was applied to predict the petrophysical properties using five wireline logs. The model’s performance and a computational function in classifying net reservoir resulted in an accuracy of 0.93, a combined precision of 0.94, a combined recall of 0.92, and a combined F1-score of 0.93. The model and methodology were deployed on a new well for validation. The classification of net reservoir zones via the proposed data analytics method, Bayes Opt-XGBoost predicted petrophysical properties, and computational function code matched mobility drawdown test data for the well. These results indicate that the developed methodology and machine learning model can work for other reservoirs since the additional computational function code can be manipulated for any data-driven estimated cut-offs. This developed approach can determine net reservoir and net pay zones in any sandstone reservoir.

Experimental investigation on the dynamic volume changes of varied-size pores during shale hydration

In order to improve the seepage channels in shale, soaking operation is often conducted after fracturing to carry out full shale hydration by the fracturing fluid. Previous research has mainly focused on the changes in the overall pore volume of shale due to hydration, but there is a lack of understanding on the volume changes of varied-size pores during the hydration process. In this study, a nuclear magnetic resonance (NMR) measurement method was carried out to obtain the size distribution of the pores in the shale in its unaltered state using ethanol as the saturation medium. Subsequently, through experiments, the shale core was saturated with fracturing fluid, and the dynamic changes in the pore size distribution under hydration were monitored using the low-field NMR technique. In addition, the relationships between the type of clay, the salinity of the fracturing fluid and the volume changes of varied-size pore were analyzed. The results of this study indicate that when the shale and fracturing fluid underwent hydration, the increase in the volumes of varied-size pores was concentrated in a certain pore-size area. This pore -size area was related to the type of clay that the shale contained. There was a strong correlation between the mixed-layer illite-smectite content and the increase in the small meso-pore volume. And the same between the illite content and the increase in the micro-pore volume. The saline fracturing fluid had an inhibitory effect on the shale hydration, mainly in the micro-pore domain. The results of this study is significant to optimize the selection of shale gas reservoirs and fracturing fluids for use in soaking measures.

A Technique of Hydrocarbon Potential Evaluation in Low Resistivity Gas-Saturated Mudstone Horizons in Miocene Deposits, South Poland

The petrophysical properties of Miocene mudstones and gas bearing-heteroliths were the main scope of the work performed in one of the multihorizon gas fields in the Polish Carpathian Foredeep. Ten boreholes were the subject of petrophysical interpretation. The analyzed interval covered seven gas-bearing Miocene horizons belonging to Sarmatian and Badenian deposits. The water saturation in shaly sand and mudstone intervals was calculated using the Montaron connectivity theory approach and was compared with Simandoux water saturation. Additionally, the Kohonen neural network was used for qualitative interpretation of four PSUs (petrophysically similar units), which represent the deposits of comparable petrophysical parameters. This approach allowed us to identify the sediment group with the highest probability of hydrocarbon saturation. Then, the spatial distribution of PSUs and reservoir parameters was carried out in Petrel. The resolution of the model was selected to reflect the variability of log-derived parameters. The reconstruction of the spatial distribution of shale volume, porosity, and permeability was performed with standard parametric modeling procedures using the Gaussian random function simulation stochastic algorithm, while PSU distribution and hydrocarbon saturation (SH) required a separate approach. The distribution into PSU groups was carried out by facies classification. Predefined ranges of clay volume, effective porosity, and permeability were used as discriminators to achieve spatial distribution of the PSU groups. The spatial distribution of hydrocarbon saturation was performed by creating the meta-attribute of this parameter and then reducing the derived pseudo-saturation model to physical values. Results included the creation of maps of hydrocarbon saturation that show the preferable areas with the highest hydrocarbon saturation for each gas horizon.

Reservoir rock typing and electrofacies characterization by integrating petrophysical properties and core data in the Bangestan reservoir of the Gachsaran oilfield, the Zagros basin, Iran

The super-giant Gachsaran oilfield is situated in the Dezful Embayment of the Zagros basin. The main goal of this study is to characterize the reservoir rock types by integrating the available geological and petrophysical studies in the Bangestan reservoir along with adopting a way to figure out the optimal number of electrofacies codes. At the first step, the types of porosity and geological microfacies were studied by using 163 thin sections from the core samples. The microscopic studies revealed that fractures and intraparticle interstices are the most common porosities types. Also, they resulted in the identification of 4 microfacies in the Bangestan reservoir. In a complementary study, the Velocity-Deviation Log (VDL) was employed to determine the dominant pore types. By comparison of the VDL values and thin section studies’ results, it was deduced that high micro-porosities along with hairline fractures are the predominant pore types of the Bangestan reservoir. At the second step, the optimal number of reservoir rock types (RRT) was determined by using the concept of hydraulic flow units. Thus, six flow units were distinguished by utilizing the Flow Zone Indicator (FZI) method in which the reservoir properties were improved from RRT-1 toward RRT-6. In the third step, the data clustering analysis, known as the electrofacies analysis, was employed to identify the accurate petrophysical rock types based on the meaningful segregation of capillary pressure curves within each electrofacies code and then propagated in non-cored intervals and boreholes. In this research, an optimal number of 7 electrofacies were identified by employing the petrophysical curves including effective porosity (PHIE), bulk density (RHOB), sonic (DT), and water saturation (SWE), along with considering the number of reservoir rock types and the defined geological microfacies, as well as the relations of the available capillary pressure data within different electrofacies codes. The validity of the proposed electrofacies was scrutinized through petrophysical results including shale volume, water saturation, and effective porosity. In the end, the electrofacies codes were compared to the defined geological microfacies. Finally, this study shows that the correlation of capillary pressure data and electrofacies codes can be resulted in figuring out the optimal number of electrofacies codes. In addition, by trying to honor the link between geological microfacies, capillary pressure, and petrophysical curves, the constructed electrofacies model, as a suitable practical integrated rock typing method, can be the foundation of property modeling, guide the spatial distribution of reservoir properties in the 3D model, aids to model the dynamics of fluid flow more realistically in reservoir simulation phase, and ultimately be beneficial for further development and production decisions in the Bangestan reservoir of the Gachsaran oilfield.

New Equations to Determine Shear Velocity from Compressional Velocity in Hf-2 Well, Halfaya Oil Field

The most important characters of the rock formations are shear and compression velocities, which are used to calculate elastic moduli. The geomechanical properties can be used to evaluate reservoir stability or to calibrate velocity and time/depth conversion, synthetic seismogram and other important applications. The aim of this study is to use the first order least square method to obtain an empirical equation to determine the shear velocity from compressional velocity for Mishrif, Rumaila, Ahmadi, and Mauddud formations in Hf-2 well. The obtained equations depend on sonic log and dipole shear sonic imager data of Hf-2 well and use Techlog software. The results from the obtained equations in comparison with those results of Green Castagna equation and measured data of dipole shear sonic imager of shear velocity for Mishrif, Rumiala and Mauddud formations. It is found from the comparison that the result is consistent each other’s. The consistent reflect the reality of shear waves values obtained in these formations. The comparison in Ahmadi formation also shows a consistent result for the obtained equations but it shows some differences from the dipole shear sonic imager and shear velocity reference values. The authors believed that the difference in some values of the Ahmadi Formation may be due to the high shale volume in comparison to the other formations.

Influence of Particle Size on the Low-Temperature Nitrogen Adsorption of Deep Shale in Southern Sichuan, China

Pore characteristics are one of the most important elements in the study of shale reservoir properties and are a key parameter for the evaluation of the potential of shale oil and gas resources. Low-temperature nitrogen adsorption is a common laboratory method that is used to characterize the pore structure of shale. However, the effect of shale’s particle size on the experimental results of the nitrogen adsorption of deep shale samples is still unclear. In this paper, using deep shale samples of different mesh sizes from the Luzhou Block as an example, we studied the effect of particle size on the pore structure of deep shale, as characterized by nitrogen adsorption experiments. The results showed that the pore volume of deep shale is mainly distributed in the mesoporous range, with a pore size ranging from 2 to 20 nm. The pore volume, as measured by nitrogen adsorption, increases slowly as the particle size decreases and then it increases rapidly. The particle size of shale has no obvious effect on the measurement of the specific surface area. The fractal dimension of deep shale gradually increases as the particle size of the shale samples increases and the smaller the particle size, the higher the correlation coefficient, R2, of the fractal dimension fitting. In this paper, different recommended sizes are given for selecting suitable particle sizes in nitrogen adsorption experiments on deep shale with different structural parameters, which will increase the accuracy of the study of the pore structure of deep shale.

Electro-sequence analysis and natural resources potential of a transitional environment in central swamp depobelt, Niger delta, Nigeria

Sequence stratigraphy and Electrosequence of the Don-Field Central Swamp depobelt of the Niger Delta Basin, was carried out using well logs, biostratigraphic and core data. The aim of this study is to re-characterise and revalidate the reservoirs within the study area and provide an optimum framework for predicting reservoir character, development and reservoir quality distribution. Detailed petrophysical evaluation reveals proficient hydrocarbon reservoir units with variable parameters (i.e. porosity, permeability and shale volume) that can accommodate productive hydrocarbon reserve. Core data analyses revealed heavy minerals like pyrites and glauconites that can be of economic interest. The gamma wireline signatures of the wells show reservoir units that are predominantly blocky in shape indicative of fluvial channels. Fluvial channels are typically associated with coastal and/or marginal marine environments. More so, the aforementioned observations were validated using palaeoenvironmental interpretation of strata penetrated by Well-1, Well-2, and Well-3 via the sidewall core analyses. Sequence stratigraphic surfaces such as maximum flooding surfaces (MFS) and sequence boundary (SB) were observed to show good correlation with palynological and foraminiferal zones. The stacking patterns (i.e. progradation, retrogradation and aggradation) encountered gave acumen into systems tracts (i.e. lowstand system tract (LST), transgressıve system tract (TST) and highstand system tract (HST) interpretation. These system tracts constitute a depositional sequence set of middle—late Miocene age bounded chronologically by MFS of 9.5 Ma, 12.8 Ma, 15.0 Ma, 15.9 Ma and SB of 12.1 Ma, 13.1 Ma, 15.5 Ma, 15.9 Ma. The SB and MFS were delineated based on Shell Petroleum Development Company (SPDC) biozonation scheme: F-zone and P-zone were within P820-P680 and F9500-F9600/F9700 as contained in the biofacies interpreted data of index fossils (Globorotalia foshi S.I; Globorotalia praefohsi; Globorotalia peripheroacuta; Orbulina spp; Praeorbulina sicana; Paragloborotalia mayeri; Neogloboquadrina acostaensis) which corresponded to the alphanumeric code N8–N16 planktonic foraminiferal zones of Blow.

Integrated wireline log and seismic attribute analysis for the reservoir evaluation: A case study of the Mount Messenger Formation in Kaimiro Field, Taranaki Basin, New Zealand

The Early Miocene Mount Messenger Formation, which represents a sand turbidite system, is the primary reservoir of the Kaimiro Field in the Taranaki Basin of New Zealand. The present study integrates the available well log and seismic attribute analyses to identify the prospective horizons' petrophysical characteristics and map them to improve understanding the reservoir characteristics. The seismic volume and well log data were imported into the Petrel 2014 software. The subsurface stratigraphic subdivisions are interpreted till 1000 ms (two-way time travel data) with the available wireline log and 3D seismic data. The workflow characterized the reservoir formation with its lithofacies architecture and interpreting its depositional evolution. The findings from the well log analysis are based on a set of charts designed by cross-plotting the various well log data against each other. These charts indicate that the reservoir comprises sandstone with some shale intercalations and also defined the boundaries between the gas sand and shale zones. The petrophysical analysis revealed that Mount Messenger is characterized by fair to good effective porosity (up to 20.5%), shale volume up to 21.4%, and hydrocarbon content up to 61%. The analyses of strata architecture and lithofacies distributions have provided the overall understanding of the subsurface reservoir sand bodies within the studied sequence. Four types of lithofacies, along with their depositional mechanisms, are identified in the study. Seismic attributes like RMS Amplitude, Half Energy and Mean Amplitude helped quantify the reservoir property of interest. The contour maps developed from the RMS, Half Energy and Mean amplitude showed the presence of significant reservoir zones i.e., 16.1%, 15.8% and 4%, within the Mount Messanger Formation. Furthermore, the identification of the Channel-Levee Complex is also established by using seismic geomorphology. The study can be extended to conduct detailed field-scale analysis can be further implied on a global scale.

Lithofacies, mineralogy, and pore types in Paleozoic gas shales from Western Peninsular Malaysia

An experimental study including Fourier Transform Infrared (FTIR), thin section petrography, scanning electron microscope (SEM) imaging, and low-pressure nitrogen adsorption analysis has been conducted to assess the mineralogy, lithofacies, pore types, and pore properties of the potential Paleozoic gas shales from Western Peninsula (WP) Malaysia. In WP Malaysia, shale samples from seven Paleozoic Formations were investigated and classified into four age categories. FTIR analysis documented the presence of aromatic out of plane and in plane bending, aliphatic CH bending, OH functional group, and presence of quartz, carbonates, kaolinite, and illite minerals. Four lithofacies identified from the petrographic analysis of the Paleozoic shale include silica-rich argillaceous mudstone (SAM), clay-rich siliceous mudstone (CSM), silica dominated lithofacies mudstone (SD), and mixed carbonate mudstone (MCM). In comparison, the mineral content and lithofacies found in Paleozoic shales are close to the Niutitang, Longmaxi, Marcellus, and Eagle Ford shales. Furthermore, with high organic matter content, laminated fabric, and with more brittle mineralogy, SD lithofacies would be a highly promising type of lithofacies in WP Malaysia. FESEM studies show that organic matter pores, interparticle pores, and intraparticle pores are the main pore types. Pore sizes analyze through N2 adsorption reveal radii of lesser than 25 nm contribute mainly to porosity and total pore volume. Micropore volume of the WP Malaysia shale was found to be greatly similar to hot shales from USA and China, while surface area values of only older Paleozoic shales, i.e., S-D and Devonian, are close to USA shales.

Application of Seismic Inversion in Estimating Reservoir Petrophysical Properties: Case Study of Jay field of Niger Delta

The conventional approach in reservoir characterization uses an extrapolation of petrophysical properties calculated from well logs in determining the entire field volume. This technique fails to acknowledge/ factor in the heterogeneity of a reservoir, and consequently leads to errors in reservoir capacity quantification. This research work employs a deterministic seismic inversion approach in determining the petrophysical properties of each reservoir sand. First, the reservoir sand was identified from intervals of low gamma-ray value with corresponding high resistivity log value. A synthetic seismogram was generated to tie the well to the seismic data and identify events that correspond to the reservoir sands. This was done by convolving the generated reflectivity series, derived from approximated Zeoppritz reflectivity with a zero-phase wavelet generated using the seismic. Acoustic impedance from the well and seismic were analyzed and proved to have a strong correlation. The impedance was then constrained with determined petrophysical parameters from the well, and it was used in generating the petrophysics base model used in the inversion. Deterministic seismic inversion was carried out to be able to determine the petrophysical properties such as porosity, the volume of shale, and water saturation that are associated with the fluids from the seismic volume of Jay-field shallow offshore of Niger Delta.

Identification of Tar Mat in Zubair Formation of the X Oilfield, Southern Iraq

The Zubair Formation was selected in the X oilfield to determine the tar zones via core, and wells logs including micro-resistivity and NMR. The study focused mainly on the main pay of the Zubair Formation, which contains a thick variable tar mat interval near the oil-water contact area, and it impacts reservoir productivity. Tar mat zones were distinguished using different paradigms such as descriptions of core and study borehole logs behavior. The result indicated that the tar mat thickness increases in the middle part of the X oil field due to the presence of high amounts of shale volume. Therefore, tar mats create barriers between oil columns and formation water, preventing the production of secondary oil in these regions.

Differences of Pore Features in Marine Shales between Lower Cambrian and Lower Silurian Formations of Upper Yangtze Area, South China

Lower Cambrian shale and lower Silurian shale are both typical of oil-prone kerogen and siliceous composition, but different in thermal maturities. Porosity differences were determined in marine shales between the two shales. Measurements were utilized including organic geochemistry, XRD, scanning electron microscopy (SEM) and N2 gas adsorption. Pore volume (PV) of lower Silurian shale was approximately 1.5 times higher than that of lower Cambrian shale, and pore surface area (PSA) of lower Silurian shale was almost 2.5 times higher than that of lower Cambrian shale. Lower Cambrian shale and lower Silurian shale possess similar materials, but distinctive thermal degrees. Evolution mechanisms of different types of pores, especially organic matter (OM)-hosted pores, may trigger this different pore features. Pores of rigid framework are the residue of primary interparticle pores during the burial history. Pores associated with clay flakes can be preserved well adjacent to rigid grains or secondary minerals acting as rigid frameworks or grain supporters. Dissolved pores in both lower Cambrian shale and lower Silurian shale barely contribute to the total porosity and mean little to the permeability. Both excessive OM content and over thermal maturity are detrimental to development of OM-hosted pores. Rigid particles, clay flakes, and OM commonly co-exist within shale matrix. Rigid grains act as supporters, clay flakes confine ample space, and OM first migrates into and provides secondary OM-hosted pores. In this condition, pores can be preserved owing to associating matrix with good mechanic and chemical stability. The significant differences of structural settings result into various hydrocarbon explosion efficiency and different pressure circumstance, which consequently leads to the different pore features between the two shales. For lower Cambrian shale, overpressure circumstance diminish if hydrocarbon expels outside of the shale system, and OM-hosted pores destroy through compaction. Sustaining overpressure and abundant residue hydrocarbon (migrated OM) make positive contributions to the pore properties, in terms of numbers, diameters and connectivity of the lower Silurian shale samples.

Determination of a potentially optimal zone to perform hydraulic fracturing work, Upper Magdalena Valley basin, Colombia

The present study was carried out for an oil field located in the upper Magdalena Valley basin, Colombia, in which successful hydraulic fracturing was carried out in a well, which we denote fractured. The main objective is to replicate this technique in an existing well in the same field. For this work, electrical logs from twelve wells, including the fractured well, were analyzed to obtain a correlation between the area of interest, located in the Monserrate Formation, and each of the wells under study. By using gamma ray, resistivity, neutron and density logs, the petrophysical properties were calculated to determine the shale volume, effective porosity, total porosity, water saturation and permeability in each well. Additionally, the production history of each of the wells and the calculations described above were used to suggest a new site where hydraulic fracturing could also be successful. Two candidates were proposed in this study, one based on the similarity of its petrophysical properties, and another based on the consideration of additional production data. Notably, this well stimulation technique has global importance and has produced positive impacts on increased oil production where it has been implemented. The purpose of this study is to provide technical support for the decision to replicate this procedure in a new area of the field.

Impact of Brittle Deformation on Pore Structure Evolution in Shale: Samples Collected from Different Fault Positions

Tectonic deformation has an important influence on the pore structure and physical properties of shale, and different parts of the same structural style also have great differences. In this study, eight shale samples were collected from two different faults based on the distance from each fault. Comparative analysis of the micro/nanopore structural characteristics and physical properties of these samples was carried out by scanning electron microscopy, liquid nitrogen adsorption, and carbon dioxide adsorption. The results show that as brittle deformation is enhanced (from far away from the fault to inside the fault), the number of organic pores decreases overall, and the connectivity of microfractures and different pore types increases. The total pore volume and total pore specific surface area of shale both increase, the pore volume of mesopores decreases by 31%, and the macropores increase rapidly by 29%. The storage capacity of shale-related folds is higher than that of shale in faults, which is more conducive to the adsorption of shale gas. The permeability of shale in faults is higher than that of shale-related folds, which is more conducive to the seepage and migration of shale gas. The organic layer structure, which is a unique and very rare microstructure at the shale fault site (under shear), was observed inside the fault. It is believed that the organic matter in the shale at the fault site has transformed from the amorphous state at the initial stage of formation to the orientation of the aromatic lamellae to stretching and extension to an increase in the pore size and the enhancement of connectivity. In addition, inorganic nanoparticles were also observed at the fault site. Both structures are important for the small pores in the fault and the increase in reservoir space. When the fault forms a closed environment or tectonic activity ceases in the later period, the early fault location likely becomes a potential high-quality hydrocarbon generation reservoir. These results help improve the understanding of the physical properties of shale reservoirs and shale gas reservoir migration within fault structures and are of great significance for shale gas exploration, development, and prediction.

Quantifying occurrence of deformation bands in sandstone as a function of structural and petrophysical factors and their impact on reservoir quality: an example from outcrop analog of Productive Series (Pliocene), South Caspian Basin

Deformation bands (DB) are known to influence porosity and permeability in sandstones. This study aims to predict the occurrence of DB and to quantify their impact on reservoir properties based on field measurements in the steeply dipping limb of a kilometer-scale fold in Yasamal Valley, western South Caspian Basin. An integrated approach of characterizing bands and their effect on reservoir properties included measurements of natural gamma radioactivity and permeability using portable tools, along with bed dip and the count of DB across distinct facies. A set of core analyses was performed on outcrop plugs with and without bands to estimate the alteration of rock properties at the pore scale. Interpretation of outcrop gamma-ray data indicates the absence of bands in Balakhany sandstones containing shale volume greater than 18% for unconsolidated and 32% for calcite-rich facies. A high amount of calcite cement appears to increase the number of DB. A poor, positive trend between bed dip and DB concentration was identified. We show that net to gross, defined as the thickness fraction of sandstone bound by mudstones, is among the parameters controlling the occurrence of bands. Samples containing a single DB show a 33% and 3% decrease in permeability and porosity, respectively, relative to the host rock. We reveal a new set of lithological and petrophysical factors influencing DB occurrence. This study offers a direct tool that can be applied in subsurface reservoir analogs to predict the occurrence and concentration of DB and estimate their influence on rock properties.

Hydrocarbon prospectivity of the miocene-pliocene clastic reservoirs, Northern Taranaki basin, New Zealand: integration of petrographic and geophysical studies

In this study, it is aimed to characterize the Early pliocene sandstone (EP-SD) and the Late Miocene-Early Pliocene Mangaa sandstone reservoirs and the efficiency of their sealing cap rocks using the petrographical and petrophysical data of these sandstone zones in northern Taranaki basin, New Zealand. The prospective potential reservoirs were studied using impregnated thin sections, XRD data analysis, and well log data (self-potential, gamma-ray, sonic, density, neutron, shallow\\deep resistivity and PEF) to characterize the reservoir zones, in addition to Mercury intrusion capillary pressure data (MICP) to check the efficiency of some potential seals. The EP-SD and the Mangaa sandstone units are typically poorly consolidated very fine sandstone to siltstone, with porosities averaging 25%. The sands are composed of quartz (38.3–57.4%), with common feldspars (9.9–15.2% plagioclase, and 2.7–6.3% K-feldspars) and up to 31.8% mica. In Albacore-1 well to the north of the Taranaki Basin, the Mangaa formation includes three separate for each of the EP-SD zones (EP-SD1, EP-SD2, and EP-SD3), and the Mangaa sequence (Mangaa-0, Mangaa-1, and Mangaa-2). The thin section studies indicate that, the studied samples are grouped into greywackes, arenites and siltstone microfacies with much lithic fragments and feldspars, sometimes with glauconite pellets. From the XRD data, it is achieved that the mineral composition is dominated by quartz, mica/illite, feldspars, and chlorite. The petrophysical investigation revealed absence of pay zones in the EP-SD zones, and presence of thin pay zone with net thickness 5.79 m and hydrocarbon saturation of about 25.6%. The effective porosities vary between 23.6 and 27.7%, while the shale volume lies between 12.3 and 16.9%. Although the shale content is relatively low, the relatively high API (50–112 API of average 75 API) is contributed by the relatively high K-feldspar content and intercalations with thin siltstone and muddy siltstone beds. Sealing units include the intra-formational seals within the Mangaa sequence, mudstones and fine grained units overlying the Mangaa and further intra-formational mudstones, within the shallower EP-SD units. The efficiency of these seals indicates the capability to trap 16.4–40.6 m gas or 17.4–43.0 m oil which is relatively low in correlation with their efficiency in the central parts of the Taranaki Basin Overlying the primary seals, mudstones of the Giant Foresets Formation provide additional regional seal.

Shale Volume Effect on Hydrocarbon Prospectivity of Green Field, Niger Delta, Nigeria

This research presents an investigation on the shale volume effect on hydrocarbon prospectivity of Green Field within Niger Delta, Nigeria. Delineation of potential reservoirs was done with Petrel Version 2010® and OpendTect 4. 6.0® exploration and production softwares, and data obtained were quality checked to eliminate null values. Three different empirical models were used to estimate the shale volume for fifteen delineated reservoirs from the three identified “Green” wells. The shale volume ranges from 0.111 to 0.162 for Green 1, 0.056 to 0.092 for Green 2 and 0.007 to 0.140 for Green 3 reservoirs. An average shale volume obtained from a merger of the three models was compared to the permeability in each of the fifteen reservoirs to determine the hydrocarbon prospectivity of the wells. It was noticed that shale volume increases with a decrease in the permeability. The ratio of shale to sand ranges from 0.125 to 0.192 for Green 1, 0.059 to 0.101 for Green 2 and 0.007 to 0.111 for Green 3 reservoirs. The presence of sand in higher volume which ranges from 0.838 to 0.889 for Green 1, 0.908 to 0.944 for Green 2 and 0.900 to 0.993 for Green 3 reservoirs than shale which ranges from 0.111 to 0.162 for Green 1, 0.056 to 0.092 for Green 2 and 0.007 to 0.140 for Green 3 reservoirs and higher resistivity which ranges from 5.61 to 96.93 for Green 1, 16.01 to 103.42 for Green 2 and 14.75 to 22.17 for Green 3 reservoirs than the conductivity which ranges from 0.0100 to 0.1800 for Green 1, 0.0096 to 0.0625 for Green 2 and 0.0450 to 0.0680 for Green 3 reservoirs are some major signals confirming a substantial hydrocarbon in the reservoirs. Results from this study indicates prospective presence of fractured shale deposits in the study area. Petrophysically, subsurface reservoirs in the “Green” field have reasonable hydrocarbons in their pore-spaces and estimated producibility indicators are good enough to support secondary migration of the oil into the borehole, if developed.

PETROPHYSICAL STUDY OF ‘GLORY FIELD’ RESERVOIR IN SOUTHERN PART OF NIGER DELTA, NIGERIA USING WELL LOG DATA

This purpose of this study is to evaluate the petrophysical properties of hydrocarbon bearing reservoirs in ‘Glory Field’ onshore Niger Delta using well log data from five wells. Petrophysical properties evaluated are shale volume, thickness, porosity, net to gross, formation factor, irreducible water saturation, permeability, water saturation, hydrocarbon saturation and pay thickness. The well logs suite contained the following logs: gamma ray, resistivity, density and neutron logs. A total of three reservoir sands (Sand A, Sand B, and C) were identified and correlated across all five wells using Schlumberger Petrel Software. From the result, on average density, Vp/Vs ratio, AI, shale volume, net to gross ratio, net thickness, effective porosity, permeability, water saturation and hydrocarbon saturation values are 2.15g/cm3, 2.28, 5406.67gcm3ms-1, 26%, 74%, 66.99ft, 25%, 2331.14mD, 48% and 52% respectively for sand A reservoir, while 2.17 g/cm3, 2.05, 6117.38 gcm3ms-1,14%, 86%, 185.04 ft, 26%, 2359.88mD, 56% and 46% respectively for sand B reservoir, and 2.18g/cm3, 2.01, 6275.95gcm3ms-1, 14%, 86%, 197.52ft, 25%, 2121.27mD, 53% and 47% respectively for sand C reservoir. The results of this research revealed very good effective porosity (>20%), excellent reservoir permeability (>1500mD) and pay zone thicknesses exceeding 70ft which are sufficient for hydrocarbon production and field development.

Evaluation of Petroleum Source Rock Using Well Logs in the Niger Delta Region of Nigeria

Petroleum source rock potential evaluation was carried out on eight wells of the Niger Delta’s Agbada Formation by assessing some source parameters from well logs and through well logs analysis based on organic matter effect and relationship on and with well logs. Source rock determinant parameters such as volume of shale (Vsh), total organic content (TOC), and amount of generated hydrocarbon (S2) was derived from well logs following established organic matter effects on well logs using Schlumberger's Techlog 2015 software, while hydrogen index (HI) was calculated using known values of TOC and S2 respectively. Well log data used for the analysis includes GR log, resistivity, sonic and Density logs. Apart from deriving source rock parameters, the well logs were also used to identify, quantify and somewhat determine mature zones of source rock intervals by correlation with TOC, S2, and HI source parameters respectively, Therefore, a source interval criterion composing of high GR log, high resistivity, high sonic and low-Density was developed alongside source rock parameters. Results of the analysis in the area show poor to fair source rock quality rating in terms of TOC, and insufficient source rock thickness fit for sustaining a world-class petroleum province like the ND petroleum province and further depicting that the Agbada FM may not be the principal source rock of the area. It is, therefore, recommended that more elaborate studies covering greater depths of the Agbada FM be carried out in other to properly represent the true source quality of the area.

Spatial assessment of gross vertical reservoir heterogeneity using geostatistics and GIS-based machine-learning classifiers: A case study from the Zubair Formation, Rumaila oil field, southern Iraq

The study of oil-field reservoir heterogeneity is an important task in the oil industry as it affects waterflooding, developing injection production systems, and optimizing hydrocarbon production. In this study, vertical reservoir heterogeneity was quantified using the Lorenz statistical index, empirical Bayesian kriging, and seven machine-learning classifiers (Classification and Regression Trees, Boosted Regression Trees, Random Forest, Naïve Bayes, Logistic Regression, K-Nearest Neighbors, and Support Vector Machine with three different kernels (linear, radial, and polynomial) under the geographic information system platform. The main pay zone of the Zubair Formation in the Rumaila oil field from southern Iraq was used as a case study. The degree of heterogeneity was first quantified using the Lorenz index, and a borehole-heterogeneity inventory location map was prepared according to the determined Lorenz index. Information about five factors influencing the heterogeneity, namely, porosity, permeability, volume of shale, reservoir-unit thickness, and depth to the top of reservoir unit, was collected based on available cores, nuclear magnetic resonance log, gamma-ray logs, and drilling-information logs. Factors from these sources were interpolated to show their spatial distribution using the empirical Bayesian kriging technique. The relationship between the borehole inventory map of vertical heterogeneity and the five factors was examined using the seven machine-learning classifiers. Two statistical-error measures, namely, accuracy and Cohen's kappa, were used to verify the performance of the classifiers in both training and testing stages. Results proved that Random Forest, Support Vector Machine with radial kernel function, and Logistic Regression were the best models. The probabilities of the best performance models were then interpolated and classified into five heterogeneity zones: Very low, low, moderate, high, and very high. The high-very high classes for each of these models approximately occupy 60% of the oil field and are mainly distributed in the middle and north of the field, whereas the other classes encompass about 40% of the field and mostly occur in the south. This distribution of classes is most likely related to the distribution and complexity of former depositional environments. • The spatial vertical heterogeneity of a clastic reservoir unit is quantified in this study. • Five factors including porsoity and permeability are used as influencing factors for modeling heterogeneity. • The high zone of heterogeneity encompasses 60% of the reservoir unit.