Application of maximum likelihood and model-based seismic inversion techniques: a case study from K-G basin, India

Seismic inversion is a geophysical technique used to estimate subsurface rock properties from seismic reflection data. Seismic data has band-limited nature and contains generally 10–80 Hz frequency hence seismic inversion combines well log information along with seismic data to extract high-resolution subsurface acoustic impedance which contains low as well as high frequencies. This rock property is used to extract qualitative as well as quantitative information of subsurface that can be analyzed to enhance geological as well as geophysical interpretation. The interpretations of extracted properties are more meaningful and provide more detailed information of the subsurface as compared to the traditional seismic data interpretation. The present study focused on the analysis of well log data as well as seismic data of the KG basin to find the prospective zone. Petrophysical parameters such as effective porosity, water saturation, hydrocarbon saturation, and several other parameters were calculated using the available well log data. Low Gamma-ray value, high resistivity, and cross-over between neutron and density logs indicated the presence of gas-bearing zones in the KG basin. Three main hydrocarbon-bearing zones are identified with an average Gamma-ray value of 50 API units at the depth range of (1918–1960 m), 58 API units (2116–2136 m), and 66 API units (2221–2245 m). The average resistivity is found to be 17 Ohm-m, 10 Ohm-m, and 12 Ohm-m and average porosity is 15%, 15%, and 14% of zone 1, zone 2, and zone 3 respectively. The analysis of petrophysical parameters and different cross-plots showed that the reservoir rock is of sandstone with shale as a seal rock. On the other hand, two types of seismic inversion namely Maximum Likelihood and Model-based seismic inversion are used to estimate subsurface acoustic impedance. The inverted section is interpreted as two anomalous zones with very low impedance ranging from 1800 m/s*g/cc to 6000 m/s*g/cc which is quite low and indicates the presence of loose formation.

A 3D geological model of a structurally complex relationships of sedimentary Facies and Petrophysical Parameters for the late Miocene Mount Messenger Formation in the Kaimiro-Ngatoro field, Taranaki Basin, New Zealand

The present study investigates the reservoir characteristics of the Mount Messenger Formation of Kaimiro-Ngatoro Field which was deposited in deep-water environment. A 3D seismic dataset, core data and well data from the Kaimiro-Ngatoro Field were utilized to identify lithofacies, sedimentary structures, stratigraphic units, depositional environments and to construct 3D geological models. Five different lithologies of sandstone, sandy siltstone, siltstone, claystone and mudstone are identified from core photographs, and also Bouma sequence divisions are also observed. Based on log character Mount Messenger Formation is divided into two stratigraphic units slope fans and basin floor fans; core analysis suggests that basin floor fans show better reservoir qualities compared to slope fan deposits. Seismic interpretation indicates 2 horizons and 11 faults, majority of faults have throw less than 10 m, and most of the faults have high angle dips of 70–80°. The Kaimiro and Ngatoro Fields are separated by a major Inglewood fault. Variance attribute helped to interpret faults, and other seismic attributes such as root-mean-square amplitude, envelope and generalized spectral decomposition also helped to detect hydrocarbons. The lithofacies model was constructed by using sequential simulation indicator algorithm, and the petrophysical models were constructed using sequential Gaussian simulation algorithm. The petrophysical parameters determined from the models comprised of up to ≥ 25% porosity, permeability up to around 600mD, hydrocarbon saturation up to 60%, net to gross varies from 0 to 100%, majority of shale volumes are around 15–20%, the study interval mostly consists of macropores with some megapores and 4 hydraulic flow units. This study best characterizes the deep-water turbidite reservoir in New Zealand.

Petrophysical Reservoir Characterization of Habiganj Gas Field, Surma Basin, Bangladesh

The previous studies on the petrophysical and volumetric analysis of Habiganj gas field were based on limited well data. As the accuracy of volumetric analysis relies greatly on petrophysical parameters, it is important to estimate them accurately. In this study we analyzed all eleven wells drilled in the Habiganj field to determine the petrophysical parameters. Analysis of the well logs revealed two distinct reservoir zones in this field termed as upper reservoir zone and lower reservoir zone. Stratigraphically, these two reservoir zones are in the Bokabil and Bhuban Formation of Surma Group. Petrophysical analysis shows significant differences between the two zones in terms of petrophysical parameters. Porosity in the upper reservoir zone ranges from 12% to 36%, with an average of 28%. This zone is highly permeable, as indicated by the average permeability of 500 mili Darcy (mD). The average water saturation in this zone is around 18% suggesting high gas saturation. The lower reservoir zone has an average porosity, permeability, and water saturation of 12%, 60mD, and 43%, respectively, indicating poor reservoir quality. An analysis of log motifs indicates that the upper reservoir zone is composed of stacked sands of blocky pattern. The sands in this interval are clean, as indicated by the lower shale volume of 12-15%. The average thickness of this zone is 230m, and the presence of this zone in all the drilled wells suggests high lateral continuity. The lower reservoir zone consists of sand bodies of serrated pattern. The sands have high shale volume and are laterally discontinuous. Overall, the upper reservoir zone has superior petrophysical properties to the lower reservoir zone. Although the reservoir quality of the lower reservoir zone is poorer than that of the upper zone, this zone can be considered as the secondary target for hydrocarbon production. Petrophysical parameters of this study were estimated from all the eleven wells drilled in this field; hence the values are more accurate. The reported values of the petrophysical parameters in this study are recommended to use to re-estimate the reserves in Habiganj field. The Dhaka University Journal of Earth and Environmental Sciences, Vol. 10(1), 2021, P 1-10

NMR AND WELL LOGS PETROPHYSICAL CHARACTERIZATION OF SANDSTONE FROM THE MARACANGALHA FORMATION, BAHIA, BRAZIL

The storage and production capacity of reservoir rocks can be estimated through some petrophysics characteristics involving the lithological identification of the constitute rocks, fluids nature in the porous space, porosity, permeability, saturation and clay content. The most popular tools for obtaining these petrophysical parameters are the conventional geophysical well logs. However, the determination of petrophysical parameters from tools based on the phenomenon of nuclear magnetic resonance (NMR) has gained prominence in recent decades. In this work, we analyzed rock samples from outcrops in Frades Island region, Bahia, Brazil, through laboratory NMR measurements, to estimate and evaluate the petrophysical properties of the Maracangalha Formation, one of the main hydrocarbons reservoirs in the Recôncavo Basin. The Sandstone samples were characterized in terms of porosity, permeability, saturation, and petrofacies. Finally, we calculated porosity, permeability, and clay content using data from gamma-ray, electrical and density logs, measured in a depth interval interpreted for Maracangalha Formation. These results corroborate with the obtained by NMR since, despite the effects of weathering and erosion on the samples used, the values of porosity and permeability obtained in NMR are in the range of values calculated from these profiles.

Bayesian Hamiltonian Monte Carlo method for the estimation of pyrolysis parameter S1

A Gaussian mixture Hamiltonian Monte Carlo (HMC) Bayesian method has been developed for the inversion of petrophysical parameters such as pyrolysis parameter S1, which is driven by a statistical shale rock-physics model. Pyrolysis parameter S1 can be used to indicate the content of free or adsorbed hydrocarbons in source rock, and it is an important indicator to evaluate the production of shale oil reservoirs. However, most studies on pyrolysis parameters are based on pyrolysis experiments and there is no relevant study to inverse pyrolysis parameter S1 from seismic data. In addition, compared to the total organic carbon content, pyrolysis S1 is more accurate for evaluating gas and oil in shale. In particular, high values of pyrolysis S1 can directly indicate the content of shale oil. We have developed a strategy for assessing shale oil sweet spots through estimating pyrolysis S1 and other petrophysical parameters. Based on the Gaussian mixture assumptions for the prior distribution of the model, we build a joint distribution to link the pyrolysis parameter S1 with elastic attributes, and then we derive a formulation to inverse S1 with the Bayesian model. Due to the components of the Gaussian mixture, the HMC method has been used to sample the posterior distribution. Our study finds that the HMC method for sampling can improve the efficiency and allow a more robust quantification of the uncertainty; also, application to real seismic data sets indicates that the delineation of sweet spots is more accurate combined with pyrolysis S1.

Formation of a Methodology for Calculating the Optimal Number of Wells in the Development of Lenticular Formations to Achieve Maximum NPV

The work is devoted to the analytical methodology for the development of oil lenticular formations. The method is based on the theory of potentials for vertical and horizontal wells. The work takes into account the interference of wells, geological and petrophysical parameters of lenses, as well as the properties of the reservoir fluid, and a new equation for estimating the inflow to a horizontal well is derived. An assessment of the correctness of this work on the company's assets was made. The dependence for the express estimation of the number of wells depending on the economic parameters at the early stages of project development is obtained.

Peculiar features of correlation between petrophysical signatures of rocks and distribution of geophysical heterogeneities in the Monchegorsk ore area (Kola Peninsula, northeastern Baltic Shield)

The current article presents stratified data on physical properties of rocks and ores from the Monchegorsk ore area (Kola region). The constructed petrodensity and petromagnetic maps reflect peculiar features of changes in petrophysical parameters of both Paleoproterozoic intrusive rocks and host rocks at the Archean basement of the area. To assess the complementarity degree of physical properties of the rocks and geophysical fields, we additionally analyzed the structure of geophysical anomalies (Δg, ΔZ) in the study area. It allowed constructing a distribution scheme for geophysical heterogeneity in the area and assessing their nature. The conducted studies showed that nickel-bearing and potentially nickel-bearing intrusions in the Monchegorsk ore area were highly dense, but composed of weakly magnetic rocks. Layering of the gabbro-labradorite massif of the Main Ridge is reflected in petrophysical parameters, i. e. endocontact gabbro and gabbronorite show an increased density and magnetic susceptibility compared to leucocratic gabbro and labradorite in the core of the intrusion. Thus, petrophysical data indicate a general increase in the basicity of the rocks towards the bottom of the intrusion. The discrepancy between intense geophysical anomalies and physical parameters of near-surface rocks of the block adjacent to the gabbro-labradorite massif of the Main Ridge in the southeast was revealed. This fact indicates a layer of dense rocks under the supracrustal basement rocks (a complex of gneisses and amphibolized volcanic-sedimentary rocks) and rocks of the Imandra-Varzuga structure. This layer can be composed of potentially nickel-bearing rocks of the Imandra complex, including intrusions of the clinopyroxene-wehrlite formation series exposed in some areas. According to the configuration pattern of the identified axes of local magnetic anomalies, the Archean blocks are considered isolated areas given the uniform pattern they create, i. e. Belomorian — isometric structures, Kola — linearly extended. Therefore, during transformation of the structural plan in the Paleoproterozoic, the Archean blocks gave differentiated responses to the emerging stress-strain state of the environment and were subject to heterogeneous deformations. The performed work, including integrated results of petrophysical studies with the analysis of the structure of geophysical anomalies in the ore region, is relevant in substantiating a strategy for prospecting for new ore occurrences and patterns of their localization, as well as for developing criteria for predicting industrial ores in the region. At the same time, the studies carried out make it possible to answer questions related to the reconstruction of the geodynamic settings that took place during the formation of the region’s crust.

Development a Statistical Relationship between Compressional Wave Velocity and Petrophysical Properties from Logs Data for JERIBE Formation ASMARI Reservoir in FAUQI Oil Field

The Compressional-wave (Vp) data are useful for reservoir exploration, drilling operations, stimulation, hydraulic fracturing employment, and development plans for a specific reservoir. Due to the different nature and behavior of the influencing parameters, more complex nonlinearity exists for Vp modeling purposes. In this study, a statistical relationship between compressional wave velocity and petrophysical parameters was developed from wireline log data for Jeribe formation in Fauqi oil field south Est Iraq, which is studied using single and multiple linear regressions. The model concentrated on predicting compressional wave velocity from petrophysical parameters and any pair of shear waves velocity, porosity, density, and fluid saturation in carbonate rocks. A strong linear correlation between P-wave velocity and S-wave velocity and between P-wave velocity and density rock was found. The resulting linear equations can be used to estimate P-wave velocity from the S-wave velocity in the case of both. The results of multiple regression analysis indicated that the density, porosity, water-saturated, and shear wave velocity (VS) are strongly related to Vp.