Gas Sands Research Articles

Bayesian stochastic inversion with petro-elastic relation to quantify thin gas sands of Khadro Formation, Zamzama gas field

Bayesian stochastic inversion with petro-elastic relation to quantify thin gas sands of Khadro Formation, Zamzama gas field

An Interface Parametric Evaluation on Wellbore Integrity during Natural Gas Hydrate Production

Based on the whole life cycle process of the economic exploitation of natural gas hydrate, this paper proposes the basic problem of stabilizing the wellbore for the basic conditions that must be met to ensure the integrity of the wellbore for exploitation: revealing the complex mechanism of fluid–solid–heat coupling in the process of the physical exchange of equilibrium among gas, water, and multiphase sand flows in the wellbore, hydrate reservoir, and wellbore, defining the interface conditions to ensure wellbore stability during the entire life cycle of hydrate production and proposing a scientific evaluation system of interface parameters for wellbore integrity.

Exploring the potential of oil and gas resources in Sichuan Basin with Super Basin Thinking

Based on the contemporary strategy of PetroChina and the “Super Basin Thinking” initiative, we analyze the petroleum system, the remaining oil and gas resource distribution, and the Super Basin development scheme in the Sichuan Basin with the aim of unlocking its full resource potential. We conclude that, (1) The three-stage evolution of the Sichuan Basin has resulted in the stereoscopic distribution of hydrocarbon systems dominated by natural gas. The prospecting Nanhua-rift stage gas system is potentially to be found in the ultra-deep part of the basin. The marine-cratonic stage gas system is distributed in the Sinian to Mid-Triassic formations, mainly conventional gas and shale gas resources. The foreland-basin stage tight sand gas and shale oil resources are found in the Upper Triassic–Jurassic formations. Such resource base provides the foundation for the implementation of Super Basin paradigm in the Sichuan Basin. (2) To ensure larger scale hydrocarbon exploration and production, technologies regarding deep to ultra-deep carbonate reservoirs, tight-sand gas, and shale oil are necessarily to be advanced. (3) In order to achieve the full hydrocarbon potential of the Sichuan Basin, pertinent exploration strategies are expected to be proposed with regard to each hydrocarbon system respectively, government and policy supports ought to be strengthened, and new cooperative pattern should be established. Introducing the “Super Basin Thinking” provides references and guidelines for further deployment of hydrocarbon exploration and production in the Sichuan Basin and other developed basins.

The Tight Sand Reservoir Characteristics and Gas Source in Coal Measures: A Case Study of Typical Areas in China

Interbedded sandstones, shales, and coal seams were formed in marine-continental transitional environments of coal measures, and the gas source of its tight sand gas has been uncertain, which hinders the progress of natural gas exploration. This article uses the Longtan tight sand gas in west Guizhou as an example to investigate the reservoir features, gas charging history, and main source rock of tight sand gas by examining thin sections, scanning electron microscopy images, X-ray diffraction results, and the fluid inclusions with burial and thermal histories and noble gas analysis. The Longtan sandstones in this study are classified as litharenites which are characterized by low compositional and textural maturities, and high clay contents, and are distinguished petrographically from conventional sandstones by the extensive existence of micropores and microfractures. The results of the homogenization temperatures of the fluid inclusions show that the Longtan tight sand gas is a single-stage accumulation which occurred during the Late Triassic. Furthermore, through the analysis of the helium and argon isotopes of noble gases, a calculation model was established for determining the shale and coal contributions to the tight sand gas. The research results show that the Longtan tight sand gas mainly belongs to the crust-derived gas, mostly from the Longtan shale-derived contribution and to a lesser extent from the Longtan coal-derived contribution. The measured 40Ar/36Ar values of the Longtan shales and coals are consistent with the forecasted 40Ar/36Ar values from the calculation model, demonstrating that the model is viable to calculate the source rock contribution to the tight sand gas. Therefore, the Longtan shales as main source rocks can generate hydrocarbons to charge neighboring tight sandstones to form tight gas accumulation in the Longtan Formation, which provides an opportunity for tight gas development in west Guizhou.

Integrated AVO inversion and seismic attributes for tracing hydrocarbon accumulation in Kafr El-Sheikh Formation, South Batra field, Nile Delta, Egypt: A case study

Utilizing advanced seismic techniques for delineating hydrocarbon accumulations in HST (High Stand System Tract) turbidite channel of Kafr El-Sheikh (KS) formation (Pliocene Age) located in the western part of South Batra field (SBF), Nile Delta – Egypt is investigated. 3D seismic data and four well logs helped in studying the properties of the channel. Three wells encountered the central part of the channel and showed thicker reservoir thickness than the fourth well, which encountered the levee. The channel is characterized by high porosity (25–30%) and relatively low water saturation (27–50%). The structural map showed that the channel is dipping towards the NE–SW. AVO analysis, scaled Poisson's ratio, post-stack seismic inversion, and seismic attributes confirmed the presence of Class III gas sand. Variance attribute helped in imaging the channel and faults. Maps generated from spectral decomposition showed that the dominant frequency is around 15 hertz. Results of integrating different techniques were consistent and successfully helped in determining the geometry of the channel, discriminating between different lithologies and fluids, in addition to delineating the sweet spots and recommended locations for drilling.

Gas Bubble Dynamics During Methane Hydrate Formation and its Influence on Geophysical Properties of Sediment Using High-Resolution Synchrotron Imaging and Rock Physics Modeling

Gas bubble in aquatic sediments has a significant effect on its geophysical and geomechanical properties. Recent studies have shown that methane gas and hydrate can coexist in gas hydrate–bearing sediments. Accurate calibration and understanding of the fundamental processes regarding such coexisting gas bubble dynamics is essential for geophysical characterization and hazard mitigation. We conducted high-resolution synchrotron imaging of methane hydrate formation from methane gas in water-saturated sand. While previous hydrate synchrotron imaging has focused on hydrate evolution, here we focus on the gas bubble dynamics. We used a novel semantic segmentation technique based on convolutional neural networks to observe bubble dynamics before and during hydrate formation. Our results show that bubbles change shape and size even before hydrate formation. Hydrate forms on the outer surface of the bubbles, leading to reduction in bubble size, connectivity of bubbles, and the development of nano-to micro-sized bubbles. Interestingly, methane gas bubble size does not monotonously decrease with hydrate formation; rather, we observe some bubbles being completely used up during hydrate formation, while bubbles originate from hydrates in other parts. This indicates the dynamic nature of gas and hydrate formation. We also used an effective medium model including gas bubble resonance effects to study how these bubble sizes affect the geophysical properties. Gas bubble resonance modeling for field or experimental data generally considers an average or equivalent bubble size. We use synchrotron imaging data to extract individual gas bubble volumes and equivalent spherical radii from the segmented images and implement this into the rock physics model. Our modeling results show that using actual bubble size distribution has a different effect on the geophysical properties compared to the using mean and median bubble size distributions. Our imaging and modeling studies show that the existence of these small gas bubbles of a specific size range, compared to a bigger bubble of equivalent volume, may give rise to significant uncertainties in the geophysical inversion of gas quantification.

Artificial intelligence model for predicting geomechanical characteristics using easy-to-acquire offset logs without deploying logging tools

This study focuses on predicting acoustic and mechanical rock properties using random forest and feed forward neural network models to evaluate the likelihood of developing efficient ways of handling absence of rock properties at offset locations. The Random Forest algorithm was used for direct prediction of the sonic data without considering the depth range of the facies; while Feed forward Neural network was used to predict the sonic data with emphasis on the lithofacies depths. The accuracy of these approaches was used in choosing the best and the most robust model for predicting sonic data when estimating formation strength and mechnical properties. Acoustic log was predicted after training a combination of caliper log, gamma log, depth, density log and resistivity log from offset wells. 5 hidden layers that accounts for the data structural complexities was included in the model architecture. A multilayer perceptron network was adopted for the Random forest algorithm to handle linear combinations of input data set. Diverse error computations were used to evaluate the performance of the model. Lastly, mechanical properties and sanding potential was evaluated using standard relations and appropriate depositional conditions. Random forest algorithm gave the best prediction accuracy of more than 96%, but the Feed forward network has the lower mean absolute error and mean squared error of 2.75 and 5.93 respectively. Generally, the predicted compressive and shear wave velocity show increase of values with depth, a behavior that is capable of identifying payzone characteristics. This was validated by the distinction seen within the 200 feet gas sand formation in the deeper portion of the studied well (9600–9800 feet). Potential failure portions of the wells, a common feature in the field, were inferred from the sanding potential computed using the predicted mechanical properties value.

Investigation of Gas-Water-Sand Fluid Resistivity Property as Potential Application for Marine Gas Hydrate Production.

The phase fraction measurement of gas-water-sand fluid in downhole is an important premise for safe and stable exploitation of natural gas hydrates, but the existing phase fraction measurement device for oil and natural gas exploitation can’t be directly applied to hydrate exploitation. In this work, the electrical resistivity properties of different gas-water-sand fluid were experimentally investigated using the multiphase flow loop and static solution experiments. The effect of gas phase fraction and gas bubbles distribution, sand fraction and sand particle size on the relative resistivity of the multiphase fluid were systematically studied. The measurement devices and operating parameters were also optimized. A novel combined resistivity method was developed, which demonstrated a good effect for the measurement of phase fractions of gas-water-sand fluid, and will have a good application potential in marine natural gas hydrates exploitation.

Early Detection of Agglomeration in Fluidized Beds by Means of Frequency Analysis of Pressure Fluctuations

For description of the fluidization state of fluidized beds, both time-domain and frequency-domain analyses of high-frequency pressure fluctuations are established approaches. Common methods for the detection of agglomeration or defluidization in fluidized beds use the variance or the standard deviation of the pressure signal or the maximum in its frequency spectrum. These methods are used, for example, in biomass combustion or gasification. However, these approaches lack the reliability for applications as an early agglomeration warning system in industrial applications. To address this issue, the present study introduces a robust methodology by means of extracting a characteristic frequency from the power spectral density of the pressure signal. A comparison of our developed approach with the commonly used frequency maximum and standard deviation for predicting the onset of agglomeration in laboratory experiments shows promising sensitivity on agglomeration formation. In order to evaluate the general applicability of this method on an industrial scale, this work investigates dependencies of possible influences, such as gas velocity, sand quantity, and temperature, on the characteristic frequency. The results indicate that the characteristic frequency can be a promising and robust method for the early detection of the onset of agglomeration in industrial plants.

Reservoir characterization for hydrocarbon detection using Amplitude Variation with Angles constrained by localized rock physics template

Seismic data are prone to ambiguities because different scenarios of geological structures and rock properties can produce similar seismic reflections. The poorly compacted sandstone reservoirs of the ‘Jay’ Field produced seismic amplitude anomalies which may not be diagnostic of hydrocarbon presence. In this study, the different seismic amplitude reflections from ‘Jay’ Field reservoirs were investigated to determine the effect of fluids and lithologies on the observed seismic amplitudes for possible hydrocarbon identification away from well location. Amplitude Variation with Angles (AVA) and Rock physics techniques were used to analyze amplitude responses from sandstone reservoirs. These seismic amplitudes were extracted from the near and far partial angle stacks to identify changes in amplitudes with angles. Reservoir properties were examined to determine their influence on seismic responses through Rock Property Template (RPT) analysis. Well logs revealed that three of the seven identified reservoirs (Sands A, B and C) are brine saturated, Sand D is oil while Sands E, F and G are gas bearing. The reservoirs stratification is mainly the juxtaposition of low impedance sandstone and high impedance shale, such that P-velocity and density significantly influence impedance contrast in sandstone reservoirs and shale lithologies respectively. Changes in seismic amplitudes from near to far angles around Well location show that the gas reservoirs produce different AVOs that correspond to Classes II, III and IV respectively. The established Well log RPT supports AVA results of gas presence in the identified area away from Well location. This helps to reduce the risk associated with seismic amplitude ambiguities and enhanced certainty of gas presence at the location away from Well log information. In similar geological scenario, this work can serve as a useful guide to gas sand detection from seismic data.

Erosion - corrosion coupling analysis of shale gas production pipe

Shale gas produced from wells contains free water, solid particles, and other corrosive substances, so shale gas production lines are at high risk of failure. The bending pipe of gas production in Shunan Gas Mine failed during service. In order to find out the causes of the failure of the bends and to provide technical support for the safe transmission of shale gas, Tensile testing machine, Vickers hardness tester, Charpy notch impact testing machine and metallographic microscope were used to test the mechanical properties and metallographic structure of the pipe sample material. The corrosion by- products were analyzed by scanning electron microscope, energy dispersive spectrometer and X-ray diffractometer. Finally, the Computational Fluid Dynamics (CFD) is used to simulate the erosion behavior of the curved pipe under different working conditions. The results show that the chemical composition, tensile strength, yield strength, hardness, impact performance and grain size grading of the gas bending pipe meet the relevant requirements. The corrosion by-product was identified as FeCO3 by the microstructure characterization analysis, energy spectrum analysis and XRD. The corrosion by CO2 was the main cause for perforation and pitting pits. CFD simulation results show that sand gas has obvious erosion phenomenon on the pipe wall, and with the increase of flow rate, the erosion rate of sand and gravel on the pipe sample increases, and the larger the particle size, the higher the erosion rate of sand and gravel on pipe sample. Combined with the erosion and corrosion results, it is concluded that the erosion of sand-bearing gas makes the inner wall material of the elbow fall off, accelerates the corrosion of CO2 on the pipe wall, and finally leads to the failure of the gas production elbow.

Study on the Stimulation Effectiveness Evaluation of Large-Scale Hydraulic Fracturing Simulation Experiment Based on Optical Scanning Technology

Summary Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development because of the undeveloped matrix pores and poor permeability. Hydraulic fracturing is one of the most critical technologies. The quantitative characterization of hydraulic fractures is of great significance to the stimulation evaluation of the reservoir, but there is still a lack of fine, effective and systematic evaluation methods. 3D optical scanning technology is widely used in the quantitative characterization of rock fracture morphology for its advantages of high speed, convenience, high precision, and nondestructive testing. In this study, after the indoor hydraulic-fracturing simulation experiments, 3D optical scanning was used to visualize the fracture network. On this basis, two aspects of quantitative evaluation methods for stimulation effectiveness were established, including: (1) evaluating the local conductivity (permeability) of different fractures by cutting hydraulic-fracturing samples. Then combining local conductivity of different fractures with the overall stimulated reservoir area, which could be more reasonable to evaluate the stimulation scope of the reservoir; (2) calculating the fractal dimension (FD) of the 3D spatial structure based on the point-cloud processing, which could directly reflect the complexity of the fracture network. Finally, a new evaluation index for stimulation (Es) was established to comprehensively assess the stimulation effectiveness of the reservoir, which was applied and verified through the indoor fracturing simulation experiments of tight sandstone from the Ordos Basin, China.

Discriminating seismic amplitude pitfall by low saturation gas using controlled-source electromagnetic technology

One of false positives in seismic amplitude associates with the presence of low saturation gas. The amplitude response is ambiguous prominently in shallow subsurface due to similar amplitude of fizz gas to highly saturated gas reservoir. This pitfall is demonstrated in Gassmann’s fluid substitution modelling which drastic velocity reduction is modeled by 5% of gas. The strong reduction induces anomalous bright spot in seismic similarly manifested by a highly gas reservoir. In pore fluid characterization, seismic amplitude of a brine reservoir is well distinguished from gas by change of response polarity from negative to positive amplitude due to higher brine modulus than gas. To a lesser extent, the negative amplitude of gas sand almost identical between commercial and non-commercial gas trap and difficult to distinguish in seismic. The similar negative amplitude of the gas cases caused by a very low gas modulus resulting to sudden drop of rock bulk modulus despite with the presence of low gas percentage. Thus, seismic velocity slows down when travels through a gas sand medium. Integration of controlled-source electromagnetic (CSEM) method in hydrocarbon prediction reduces exploration risk by only detecting commercial hydrocarbon. It exploits resistivity contrast between overburden and hydrocarbon reservoir which highly controlled by hydrocarbon saturation. CSEM normalized response exceeds the cut off response by a minimum saturation of 70% of gas. Less than 70% of gas, CSEM response is below the cut off response which considered as insignificant anomaly in CSEM measurement. It becomes a key strength as this method reduces amplitude uncertainty in seismic due to low saturation gas and potentially improves the chances of economic discovery in hydrocarbon exploration.

Depositional environment characterization in deltaic system by utilizing core, well log and seismic attribute data, Northern Malay Basin

The heterogeneity of shallow marine facies is quite hard to be solved. However, integrating all the data is essential to determine the details of facies distribution, whereas facies characterization is an important part that should be done before the petrophysical characterisation. This study aims to evaluate the reservoir depositional facies distribution using seismic well log and core data based on sequence stratigraphy concept, seismic interpretation, and seismic attributes, thus reducing the risk of oil exploration and improving the success rate. To ensure the objective is achieved, sequence stratigraphy interpretation has been done using integrating well log, core, and seismic data to identify the depositional environment. Distribution of coal helps to create well log correlation. Lithofacies and fluid have been interpreted according to core, test and log patterns, such as; gas sand, brine sand, shale, and coal. Based on the characteristic of logs, biostratigraphy and core data, five depositional environments have been interpreted in this study including in-distributary channel, delta plain (flood plain shale), crevasse splay, delta front shale (prodelta), and mouth bar. The interval of the target area is generally influenced by regression systems where on the lower formation is dominated by the transition depositional environment and changed to be dominant of delta plain.

Reducing the risk of low saturation gas using controlled-source electromagnetic (CSEM) in K-Field, Central Luconia: a forward modeling case study

The application of controlled-source electromagnetic (CSEM) in hydrocarbon exploration significantly facilitates the detection of economic hydrocarbon. The method captures anomalies through the resistivity contrast between the overburdens and hydrocarbon-bearing lithologies. In most cases, the resistivity contrast is only prominent when there is sufficient hydrocarbon saturation. K-Field is situated on the continental shelf of Sarawak Basin, a sub-mature area for oil and gas in the Central Luconia province. Despite the low saturation of the gas in the Cycle VI sand, the seismic data shows a strong amplitude in the shallow section. Therefore, this study is conducted to assess the change of resistivity and CSEM response to the gas saturation and thickness variations of thin-gas sand in the K-Field. 3D resistivity models and three exploration wells are provided and two main methods are implemented in this study comprising the resistivity and CSEM forward modelings. The resistivity modeling is conducted using the Indonesia water saturation equation for different gas saturation scenarios and subsequently, the modeled resistivity is inputted in 1D and 2.5D CSEM forward modeling. The modeled CSEM response analysis is done by normalizing the modeled CSEM amplitude to the background or also known as normalized amplitude response (NAR). In gas saturation variation, the modeled resistivity showed an insignificant resistivity increase from 0.45Ωm to 0.55Ωm from wet case to 5% of gas and strongly increases to 35Ωm at 90% of gas saturation. The 1D CSEM NAR shows a very weak response of less than a 3% increase for 5% of gas and up to 230% increase for 90% of gas. In gas thickness variation, the CSEM NAR is weak and less than a 15% cutoff for all the tested thicknesses for 5% and 45% of in-situ gas. At 70% of gas, 25m is the minimum detected gas thickness with a 17.5% response increase, and at 90% of gas, the response is already strong at a minimum 5m thickness with a 35% increase. The modeled 2D CSEM responses also show that only 70% and 90% of gas sand layers in the K-field were delineated distinctively by the inline receivers with a 40% and 200% response increase respectively.

Rock Physics Modeling of Gas Hydrate Reservoirs Through Integrated Core and Well-Log Data in NGHP-02 Area in KG Offshore Basin, India

Since gas hydrates are unconventional reservoirs, they pose unique challenges for identification, characterization, quantification, and extraction. The conventional approach—elastic logs—can provide a better method for identification through attribute analysis. On the other hand, geomechanical studies for wellbore stability analysis pave the way for the effective exploitation of gas hydrates. It is crucial to predict elastic logs against gas-hydrate-bearing sediments, which requires an effective rock physics model. In the present work, a study pertaining to the National Gas Hydrate Program-02 (NGHP-02) campaign in the Krishna‐Godavari (KG) Offshore Basin, India, where gas hydrates are deposited primarily in two facies—a shale-dominated shallower one and a sand-dominated deeper one that has been identified by responses of conventional and spectroscopy logs—is discussed. It is commonly known that depositional heterogeneity impacts petrophysical and elastic properties. To address this issue, an innovative approach has been adopted to model compressional and shear log data using rock physics modeling of gas hydrate reservoirs based on the depositional type of gas hydrate. Guidance from the change of compressional velocity data from log and core with an increase of gas hydrate saturation shows gas hydrate deposition in the study area can be explained through a matrix/grain-supported model. The Jason grain-supported rock physics model appeared best suited among different available rock physics models, depending on the clay volume and porosity in our study area. Using input from a robust multimineral petrophysical evaluation and rock physics modeling, the finalized model is propagated to test wells for predicting compressional, shear, and density logs, with the predicted data validated by core-measured compressional and shear data. Model consistency is indicated by a high correlation from multiwell crossplots of modeled and recorded elastic logs (compressional and shear velocity) with acoustic impedance. The developed rock physics model better discriminates gas hydrate in the shaly sand layer and gas hydrate in the sand-dominated layer, calcite, and shale in the VpVs domain.

Simulation Analysis of Temperature Effects on the Shear Behavior of Gassy Sand

The gas in gassy sand is enclosed in the pores of soil skeleton mainly in the form of dissolved in water or free gas bubbles, which is considered to be a perfect equilibrium composed of soil particles, pore water, gas, temperature, and overlying pressure. If any of these elements changes, this balance will be destroyed, resulting in disturbance in its mechanical properties. It is generally assumed that the existence of closed gas bubbles will not affect the soil skeleton but increase the compressibility of pore fluid. Assuming that the closed gas bubbles follow Boyle’s law and Henry’s law, the relationship between pore pressure change and volume strain is established. On the basis of the constitutive model which can reflect the temperature characteristics of saturated sand proposed by the author previously, combined with the special characteristics of gassy sand, the effect of temperature effects on the shear behavior of gassy sand is preliminarily explored and analyzed. The results show that under the condition of drained shear, the increase of temperature will increase the shear strength of gassy sand, and the simulation results are in good agreement with the test data. Under the condition of undrained shear, the shear strength of loose gassy sand increases with the increase of temperature, while that of dense gassy sand decreases. Moreover, the larger the gas volume, the more obvious these phenomena tend to be. However, only qualitative simulation analysis is carried out for undrained shear, which needs further verification in combination with relevant tests.

Gas and water distribution in the tight gas sands of the northwestern daniudi gas field, ordos basin, China: Impact of the shale barrier

The production of gas from the Upper Paleozoic tight sands in the Daniudi gas field, Ordos Basin, China, is hindered by a lack of knowledge of the factors controlling water distribution. This study aims to clarify the origin of the water, reduce unwanted water production, and detect probable locations of “sweet spots”. A geological study during field development was conducted in the northwestern region of the gas field by integrating production data with other core, well log, mud log, and geological data. The results showed that the gas and water distribution was apparently related to gas charge, with a close negative correlation identified between the thickness of shale barrier and the cumulative gas production on a per well basis. Therefore, the shale barrier has the significant influence on the fluid distribution in the study area. In addition, the shale barrier was found to play a dual role in hindering gas charge toward the upper reservoir and in sealing trapped gas in the lower reservoir, given the configuration of “gas generation below and gas storage above”. This implies the wax and wane relationship. Insights on the shale barrier’s effect contribute to an alternative strategy of “sweet spot” prediction for resource development in unconventional gas reservoirs, i.e., if improved technologies are currently lacking to discriminate between gas-bearing and water-bearing zones in tight gas sands, the spatial distribution of continuous shale can be predicted with 3D seismic data as an initial step, which is thought to be less difficult. The attempts to detect “sweet spots” should subsequently focus on the local area where the thinner shale barrier exists below the producing zone. This work not only can enrich the theory of hydrocarbon accumulation in the Ordos Basin, but also presents an analogue to tight sand gas for worldwide sedimentary basins.

An integrated approach of reservoir characterization of Y gas field in Central Bredasdorp Basin, South Africa

The study attempts to address the knowledge gap in the Bredasdorp Basin Offshore South Africa by using newly acquired seismic data with an enhanced resolution, integrating core and well log to provide a solution. The main objective of this study was a volumetric sandstone reservoir characterization of the 13At1 and 10At1 sandstones deposited in the upper shallow marine environment. The results reveal four facies grouped as facies 1(claystone), facies 2(intercalation of claystone and sandstone, facies 3(medium sandstone), and facies 4 fine-medium sandstone grain deposited in a deep marine environment. Facies 3, the medium-grained sandstone, has the best reservoir quality rock, while facies 1, which is predominantly claystone, has the least rock quality. The study has produced a calculated volume of gas in the 10At1 sand (upper and lower sand is 30.01 billion cubic feet (bcf)) higher than that of the 13At1 sand (27.22 bcf of gas). Improved seismic resolution enhanced the accuracy of results. It is advisable to focus further field development in the eastern part of the Y gas field because of good reservoir quality and production developed due to the sand in the 10At1 sequence.

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.