Water Saturation Values Research Articles

Using the Conventional Method to Estimate Water Saturation of Khasib Formation in East Baghdad Oil Field Central Area

The water saturation level may change due to geological changes or human intervention, like earthquakes, excavation, injection, or extraction of fluids from underground reservoirs. This work helps the reader understand how to use electrical logging to acquire a suitable water saturation value in resistivity and dielectric studies. In the East Baghdad field, two wells that were drilled into the Khasib Formation had their petrophysical parameters assessed using IP software. This allowed for the determination of water saturation using the available well logs, including neutron, density, SP, sonic, gamma ray, and resistivity logs for wells EB-25, and EB-29. The limestone section in the Khasib formation represents calcite, the main mineral found. We counted the amount of shale in each well using gamma-ray logs. The porosity at the reservoir unit was determined using a sonic log. Archie's equation and resistivity data are also used to compute fluid saturation. Taking m=n=2, a=1, x=1.76, and Rw=0.033 for Khasib formation. The link between Archie's and Raiga's coefficients, a, m, n, and x, is primarily the basis for this discussion. There is high agreement when this equation is used. In clean formations (non-shaly). this formula can be regarded as a reliable indicator of water saturation in situations where porosity techniques other than acoustic logs are unavailable. It's important to note that this equation provides accurate and realistic answers for rocks with transit times between 40 and 150 As/ft. Porosity knowledge is not required for such an assessment.

A Petrophysical Properties Evaluation Study of a Niger Delta Field Using Well Logs and Core Data

A petrophysical properties evaluation study of an onshore field “NEMA” was carried out to assess the petrophysical characteristics of the field in the eastern portion of the Niger Delta Basin. This was done in an effort to determine the hydrocarbon prospect and oil productivity potential of the reservoirs. The net/gross thickness was one of the examined parameters. (pay zone thickness), porosity, permeability, fluid saturation which were all inferred from geophysical wireline logs and core data. The wireline logs used in the investigation included density, resistivity, gamma ray, and spontaneous potential logs for five different wells from the “NEMA” oil field. Five reservoirs designated, NEMA 01, NEMA 04, NEMA 07, NEMA 09, and NEMA 12 were identified and correlated across the five wells in the field using gamma ray logs and shale resistivity markers. Based on the computation of petrophysical parameters, the porosity of the reservoirs ranged from 0.22 (22%) to 0.31 (31%); the permeability ranged from 851.58 mD to 1005.05 mD; the average net-to-gross thickness of the reservoir sand bodies was 140 ft; the water saturation value was less than 45%, while the hydrocarbon saturation was greater than 55%. We equally observed that our computed petrophysical parameters from well log data correlated well with the core computed values in NEMA 09. In conclusion, the delineated reservoirs were categorized as good hydrocarbon reservoirs. These results suggest huge hydrocarbon potential and a reservoir system whose performance is considered satisfactory for hydrocarbon production.

Determining the influence of compaction methods on the physical-mechanical properties of asphalt concrete samples

The object of this study is the compaction methods of asphalt mixtures under laboratory conditions. The experience of determining the physical properties of coarse-grained asphalt concretes taken from the layers of the road pavement structure shows that their values do not correspond to those of the samples obtained by laboratory compaction using the pressing method. In 90 % of cases, the density of cores exceeds the density of laboratory samples while the indicators of void content and water saturation are significantly lower than for laboratory samples. The compressive strength indicators of asphalt concrete are almost independent of compaction methods and are not very informative. All of the above leads to the conclusion that the methods of laboratory compaction by pressing do not meet modern requirements. Low values of water saturation and void content of cores and laboratory samples compacted with a gyrator allow us to argue about outdated approaches to the design of grain compositions of asphalt concrete. Low-informative indicators of compressive strength indicate the need to use other mechanical characteristics that will make it possible to predict the properties of asphalt concrete in the pavement, for example, rutting resistance. As a summary, template solutions in the design of asphalt concrete warehouses and physical and mechanical characteristics are necessary only to establish compliance with the requirements of regulatory documents. The current work shows that it is almost impossible to predict the properties of asphalt concrete based on laboratory samples obtained by pressing. All this leads to the need to change the regulatory framework, which is possible by using regulatory documents of the countries in the European Union and the United States of America

Utilization of abandoned oil well logs and seismic data for modeling and assessing deep geothermal energy resources: A case study

Hammam Faraun (HF) geothermal site in Egypt shows potential for addressing energy demand and fossil fuel shortages. This study utilizes abandoned oil well logs, seismic data, and surface geology to assess HF geothermal energy resources.Seismic interpretation identified a significant clysmic fault parallel to Hammam Faraun fault (HFF), named CLB fault. The two faults together create a renewable geothermal cycle through circulation of mixed formation-sea waters.Petrophysics revealed two main geothermal reservoirs: the Nubian sandstone reservoir and the Eocene Thebes carbonate reservoir with water saturation values approaching 100 %. Corrected borehole temperatures indicated reservoir temperatures around 120 °C and 140 °C for the Thebes and Nubian reservoirs, respectively.Fracture analysis and stress state provided insights into subsurface fractures. A geomechanical model demonstrated the impact of different stresses and pore pressure on geothermal fluid flow. NE-SW oriented fractures showed a higher dilation tendency due to aquathermal expansion.The integrated conceptual geothermal model suggested a magma chamber beneath HF as the heat source, related to Oligo-Miocene volcanic activity. The breached relay ramp and fault-related open fracture system serve as pathways for geothermal fluids.Evaluation of the geothermal potential utilized volumetric calculations and Monte Carlo simulation. The estimated hot water volumes were 1.72 km3, 4.242 km3, and 5.332 km3 for the Nubian reservoir in the onshore part, Thebes reservoir in the offshore part, and Nubian reservoir in the offshore part, respectively.The results indicate a medium enthalpy resource suitable for electricity generation using a Kalina geothermal power plant. The predicted geothermal power output is promising, with an average power output of 9.64 MWe, 21.38 MWe, and 43.76 MWe for the Nubian reservoir in the onshore part, Thebes reservoir in the offshore part, and Nubian reservoir in the offshore part, respectively. These outputs can potentially supply electricity to approximately 12,000, 29,000 and 53,000 households, respectively.

Determination of Hydrocarbon Production Zones using Well Logging Data in the "North_Rawa" Well of the South Sumatra Basin

Petrophysical analysis with well logging is carried out to determine the value of petrophysical parameters of rocks in the formation. Then to find out information about the subsurface structure as well as the depth zone of layers containing hydrocarbons and the types of hydrocarbons from the production field. In this research, an evaluation of reservoir formation was carried out in the North_Rawa field of the South Sumatra Basin, based on petrophysical log analysis from data from three wells in the North_Rawa field. Reservoir identification results from physical rock parameters such as porosity, shale content, water saturation and permeability obtained from formation evaluation calculations. Porosity is calculated to determine the pores, shale content is calculated to determine the volume of shale in the reservoir, water saturation is calculated to determine the water content in the formation, and permeability is calculated to determine the rock's ability to pass fluid. The results of petrophysical calculations were obtained in the hydrocarbon prospect zone in the North- rawa 1 well at a depth of 3387.5 – 3938 feet, the North- rawa 3 well at a depth of 2667.5 – 3735.5 feet, the North- rawa 4 well at a depth of 2759.5 – 3775 feet. The average porosity values for each well are 8%, 15.4%, 16%. The average shale content value for each well is 61%, 48%, 53%. Average water saturation values are 61%, 54%, 68%. Average permeability values 46.7 mD , 98.9 mD , 3.38 MD. The hydrocarbon prospect in the research well contains natural gas and oil hydrocarbons with sandstone and shale formation lithology.

Petrophysics of Low Resistivity Reservoir

Low resistivity reservoirs have long been known in the oil and gas industry as reservoirs that have significant potential and contribution to oil and gas production. This reservoir is very unique because of its relatively low resistivity readings (< 5 Ohm) and often other log responses do not show the way carbonate-containing reservoirs do, so they are often overlooked and not considered as potential carbon reservoirs. The low resistivity reading also causes the Water Saturation (Sw) value to be too high, which contributes to why the reservoir is overlooked. Theoretically, the factors that cause low resistivity readings are high clay/shale content, fine grain size, high salinity air formation, presence of microporosity and presence of conductive minerals which affect resistivity log readings in addition to other things such as low structured reservoirs. and there is a significant slope of the layers. Based on statistic reports, generally in low resistivity reservoirs there is a combination of two or more of the causal factors mentioned. This study aims to identify the characteristics of low resistivity reservoirs in the Upper Cibulakan Formation, West Java Basin, especially from log readings and recognition of what factors support reservoir formation both from the results of core and log analysis as well as selecting combinations for calculating water saturation. From the low resistivity reservoir characteristics, it is hoped that it can be used to find and identify the distribution of similar reservoirs so that potential reservoirs that have been overlooked so far can be identified, discovered and developed which in the end are expected to provide additional contributions both in terms of education and for the oil and gas industry in finding new reserves for oil and gas production in Indonesia.

Material balance evaluation method for water-bearing gas reservoirs considering the influence of relative permeability

In this paper, we developed a material balance method based on a two-phase flow equation for evaluating the development efficiency in gas reservoirs. The calculating results show that the theoretical curves of development performance simulated by material balance fit well with early production data and can be used to evaluate the development efficiency of the field. The influence parameters of the theoretical curves were analyzed by simulating a constant production gas reservoir. The results show that the numerical differences between the initial water saturation and the water saturation at the isotonic point of the relative permeability curve greatly influence the theoretical curves. The higher the ratio of water phase relative permeability to gas phase relative permeability, the higher the water-gas ratio in the early and middle periods of well production. It is beneficial to exploit the underground fluid with a large average rock compressibility coefficient which means a strong formation elastic energy. Besides, the value of initial water saturation will also influence the loss of formation elastic energy. This study extends the applicability of material balance and avoids the cost risk of field well testing. Therefore, it has a good practical significance.

PETROPHYSICAL CHARACTERIZATION BY 3D MODEL OF ZONES 4 AND 3 OF THE TURONIAN RESERVOIR OF THE KINKASI FIELD IN THE D.R. CONGO COASTAL BASIN

Kinkasi is one of the oil fields of the DR Congo Coastal Basin. It is essentially formed of two main geological units (A and B) in the Turonian, each composed of a succession of different horizons (Zones) according to the type of siltstone. These two main units contain 6 Zones. Unit A consists of Z6 and Z5 of Coniacian age, while the rest of the reservoir (Z4, Z3, Z2 and Z1) is of Turonian age which is characteristic of Unit B. Indeed, the present study is devoted to the petrophysical characterization of the two zones Z4 and Z3 of the unit B in order to locate the interesting zones to develop this oil field. For this fire, we used the data of 11 wells having the geographical coordinates, the porosity, the permeability as well as the water saturation. The processing and interpretation of these data using the Kriging method allowed us to deduce from the scale of appreciation the areas that contain high values of porosity, permeability and water saturation. Porosity in zones 4 and 3 varies from good to very good, saturation 3 to 59% for zone 4 and 32 to 53% for zone 3 as well as permeability from poor to low for both zones. The combined interpretation of these three properties allowed us to find an interesting zone located towards the east of zones 4 and 3 with high porosity and permeability values and low water saturation values.

Evaluation of Carbonate Reservoir with Integration of Petrophysical Analysis and Seismic Impedance Inversion in Banggai Basin, Sulawesi

Banggai Basin is controlled by the collision between Banggai-Sula micro-continent and East Sulawesi ophiolite belt, forming a thrust-sheet anticline structure that has potential to trap hydrocarbon. The Siotu-1 well was drilled right into the thrust-sheet anticline structure targeting Miocene carbonate platform layer. The same structure has proven to be an oil trap at the Tiaka oilfield which is located adjacent to the Siotu-1 well. This study aims to evaluate the presence of hydrocarbon in the Siotu-1 well with characterization of the Miocene carbonate reservoir. It is carried out by integrating petrophysical analysis from the Siotu-1 well log data and 2D seismic impedance inversion of the Tarib-1 line. Five reservoir zones have shale content values range of 21.91-37.53%, effective porosity values range of 9.7-14.62%, water saturation values range of 88.5-98.27%, and permeability values range of 2.53-8.16 mD. The results of the porosity calculation are validated by the model of seismic inversion where the reservoir zone with an acoustic impedance in the range of 7600-13450 ((m/s)/(g/cc)) is a carbonate layer with fair to excellent porosity (10 to> 25%) and reservoir zone with acoustic impedance values range of 13450-16200 ((m/s)/(g/cc)) as carbonate layer with poor porosity (< 10%). The net pay zone in reservoir zone 4 with a thickness of 4.5 feet and a net-to-gross of 0.006 are shown as the lumping result. It is concluded that Miocene carbonate reservoir in the Siotu-1 well met the criteria as a good reservoir rock but insignificant of hydrocarbon potential for further development.

Identification Analysis of Fluid Type in the Low Resistivity Zone of Well Z-2 Field "Z", South Sumatera

Hydrocarbon reserves are one of the main points that are very important in the sustainability of the productivity of an oil and gas field. This important point is greatly influenced by several parameters that can be obtained by various measurements and analysis. One of the most influential parameters in the analyses of the amount of hydrocarbon reserves in a reservoir is the water saturation value. The water saturation parameter will also be greatly influenced by the electrical parameters of the fluid-containing rock in the reservoir. Sometimes the electrical parameters of this rock, in this case resistivity becomes one of the benchmark parameters, whether the zone or reservoir has potential or is interesting to be developed or produced. However, there are several reservoirs or zones that experience low resistivity effects which will give an initial indication that the zones or reservoirs are not attractive or have no effect on development. In this Z field, there is a zone that experiences low resistivity effects, making this zone unattractive for production. So to be able to make these zones attractive for production, an identification analysis was carried out on Zones A and B in this Z field to determine the type or type of fluid from the two zones. The initial analysis was carried out petrographically from rock sample incisions at certain depths in Zones A and B so that it is known that the cause of the low resistivity effect in the two zones is the presence of pyrite minerals and illite clay which are the main causes of the low resistivity effect. Furthermore, an analysis of the identification of fluid types was carried out using the double apparent resistivity method with the results obtained that in Zones A and B there are 2 types of fluids, namely hydrocarbons and water with a depth limit of 3650 ft in Zone A and 4558 ft in Zone B. By knowing the type of fluid, the hydrocarbons contained in these two zones should be able to increase interest in the production of these zones as a potential zone for production, but it is necessary to perforate at a depth range indicated by the hydrocarbon fluid and carry out initial production tests to prove the results of the analysis in this study.

Fundamentals-Based Alternative Addresses Issue With Three-Phase Permeability Model

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205883, “Issue With Stone II Three-Phase Permeability Model and a Novel Robust Fundamentals-Based Alternative to It,” by Subodh Gupta, SPE, Heretech Energy. The paper has not been peer reviewed. _ The objective of this paper is to present a fundamentals-based, three-phase flow model consistent with observation that avoids the pitfalls of conventional models. Though the use of the Stone II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears counterintuitively to limit the flow of oil when water is present near its irreducible saturation. The novelty of the work presented in the complete paper is in the development of a model based on fundamentals of flow in fine channels that better explains observed results in the context of flow in porous media. Problem Definition Residual oil saturation (So) from retrieved cores from oil-drained chambers of steam-assisted gravity drainage (SAGD) reservoirs invariably shows values as low as 1 or 2%, whereas reservoir simulations using Stone II-based relative permeabilities (an industrywide favorite) predict significantly higher numbers (14–18%). In previous work, the author and others, in an attempt to remedy the situation, extended the oil-phase relative permeability in the presence of the water phase (krow) and oil-phase relative permeability in the presence of the gas phase (krog) curves all the way to water and gas saturation values less than unity; however, they discovered that, in the presence of water saturation (Sw) near the irreducible water saturation (Swi), the use of the Stone II formula for oil relative permeability still resulted in high residual So. Correct estimation of residual oil-phase saturation is even more important for solvent/steam mixed thermal recovery processes such as solvent-aided processes, where a small amount of solvent is added with steam in SAGD, and significantly more important for solvent-dominated processes, where a small amount of steam or heat is added with a large amount of solvent. A large amount of residual oleic-phase saturation and associated pessimistic solvent-recovery prediction will lead to erroneous economic assessment of these processes. The discrepancy in residual So, as the author and coauthors discovered in previous work, stems from a peculiarity of the Stone II formulation given by Equation 1 of the complete paper. To model this 1D problem numerically, a program developed by the author for his PhD thesis for modeling of moving front reservoir processes with dynamic gridding was modified and run with constant fluid properties for hexane and water at constant pressure and temperature. It also incorporated the three-phase relative permeabilities given by Equation 1 and Table 1 of the complete paper. The results are shown in Fig. 1.

Petrophysical properties and volume estimation of hydrocarbon resources in x field, onshore niger delta: A reservoir characterization study

A reservoir characterization study was conducted on three wells located in X Field, situated in the Onshore region of the Niger Delta. A suite of conventional digital well logs was utilized to identify hydrocarbon-bearing reservoirs, determine reservoir petrophysical parameters, and infer the depositional environment. The study delineated four hydrocarbon-bearing reservoirs, labeled A, B, C, and D, with porosity estimates ranging from 25% to 27%, and permeability values varying from 1863.22md to 2759.78md. These results suggest that the reservoirs have good storage capacity and permit free flow of fluids, consistent with prior research in the Niger Delta. The water saturation values, ranging from 43% to 70% for Well X and 53% to 94% for Well Y, indicate the presence of significant hydrocarbon in reservoir C, while Well Z did not contain any hydrocarbon. The estimation of oil and gas resources indicated that Well X contains 1.11 X 105 barrels/acre of oil and 5.16 X 107 cubic feet/acre of gas, while Well Y contains 4.43 X 106 cubic feet of gas. The analysis of the volume of shale (0.15-0.19) revealed that the reservoirs range from slightly shaly sand to shaly sand. Based on the log motifs, the study suggests that the reservoirs are mainly fluvial channel deposits, and the rapid alternation of thin beds of sand and shale indicates deposits of delta progradation and river floodplain deposits.

Reservoir characterization, in relation to the petrophysical modeling of Baharyia formation, Razzak field, northern western desert, Egypt

The present work aims to investigate the reservoir characterizations of the Lower Cenomanian Baharyia Formation by creating isoparametic maps to calculate the petrophysical parameters and detect the favorable parts for oil accumulations using the available well logging data. Baharyia Formation is one of the main hydrocarbon sandstone reservoirs in the northern Western Desert of Egypt. About 90% of the Western Desert field produces form Baharyia sandstone Formation. This has been achieved through the analyses of the conventional wireline logs and petrophysical modeling. The Baharyia Formation comprises a complex of depositional lithofacies such as interbedded siltstone, shale, sandstones and pebbly sandstones. Petrophysical modeling of the Baharyia Formation was performed, based on the interpretation of complete wireline logs from five wells in Razzak oil field, north Western desert, Egypt. Petrophysical analysis accomplished, such as: shale volume, total and effective porosities, water saturation and hydrocarbon saturation, were deduced and utilized in the petrophysical subdivision of the Baharyia Formation. Relations between theses petrophysical parameters are established to define the implications of such parameters on the Baharyia Formation. Iso-parametric and litho-saturation crossplots are used to delineate variations in petrophysical parameters across the area. The obtained petrophysical results reveal that, the Baharyia Formation have a good reservoir quality, with high effective porosity values exceeding 18%,volume of shale about 30% and low water saturation values of 25%. The rock genetic types of the Baharyia Formation deduced form the log curve shapes proved that the Baharyia Formation was deposited from fluvial to marine environments passing through the tidal flood plain conditions. However, the lithology of the Baharyia Formation composed of sandstone, siltstone, shale and minor limestone inter-beds.

A New Method for Calculating Reservoir Core-Bound Water Saturation Using the Cast Thin Section

The rock coring of the reservoir in the Bohai A field is difficult. The cores of the target section in the study area are loose, making it difficult to accurately measure the core-bound water saturation. The purpose of this research was to develop and validate a method for calculating a reservoir core-bound water saturation ratio using the cast thin section. First, pepper noise denoising and image enhancement were performed on the thin section by median filtering and gamma variation. Based on this, the enhanced sheet images were thresholded for segmentation by the two-dimensional OTSU algorithm, which automatically picked up the thin section pore-specific parameters. Then, the thin section image was equivalent to a capillary cross-section, while the thin film water fused to the pore surface was observed as bound water. For hydrophilic rocks with a strong homogeneity, the area of thin film water in the pore space of the sheet was divided by the total area of the pore space, which produced the bound water saturation. Next, the theoretical relationship between the film water thickness and the critical pore throat radius was derived based on the Young–Laplace equation. The bound water saturation of the rock was calculated by combining the pore perimeter and the area that was automatically picked up from the thin film for a given critical pore throat radius of the rock. Finally, 22 images of thin sections of sparse sandstone from the coring well section of the study area were image processed using the new method proposed in this paper, and the bound water saturation was calculated. The calculated results were compared with 22 NMR-bound water saturations and 11 semi-permeable baffle plate-bound water saturations in the same layer section. The results showed that the bound water saturation values calculated by the three methods produced consistent trends with absolute errors within 5%. The calculated results confirm the reliability of the method proposed in this paper. This method can effectively avoid the problem of the inaccurate results of core experiments due to the easy damage of sparse sandstone and provides a new idea for the accurate determination of the bound water saturation of sparse sandstone.

Integrating Petrophysical Analysis and Seismic Interpretation for Oil and Gas Reserves Estimation in “TAU” Field, Jatibarang Sub–Basin, North West Java Basin

The focus of the study is the North West Java Basin, specifically the Jatibarang Sub Basin within it. The research aims to identify new potential areas for hydrocarbon reserves using seismic interpretation, and tetrophysical analysis, also calculate the volume of reserves in those areas. According to the study, 2 potential areas for hydrocarbon reserves were identified in the Parigi Formation, 2 were identified in the Baturaja Formation, 3 were identified in the Talang Akar Formation, and 1 was identified in the Jatibarang Formation. No new potential areas were discovered in the Cibulakan Formation. The study used petrophysical interpretation of six wells to determine the average values of shale volume (9.57% to 29.87%), effective porosity (19.45% to 21.67%), and water saturation (69.73% to 93.50%) for each potential zone. The TAU-5 well in the Baturaja Formation (Zone 1, Zone 2, Zone 3, and Zone 4) was determined to be the most economically viable zone for production based on the values of shale volume, porosity, and water saturation. The volume of hydrocarbon reserves in the BR-1 potential zone was calculated to be 182.741281 MBO in OOIP and 177.85122 BCF in OGIP. The BR-2 potential zone had an OOIP value of 1,197.534148 MBO and an OGIP of 1165.488764 BCF.

Effects of Compression and Porosity Gradients on Two-Phase Behavior in Gas Diffusion Layer of Proton Exchange Membrane Fuel Cells

Water management within the gas diffusion layer (GDL) plays an important role in the performance of the proton exchange membrane fuel cell (PEMFC) and its reliability. The compression of the gas diffusion layer during fabrication and assembly has a significant impact on the mass transport, and the porosity gradient design of the gas diffusion layer is an essential way to improve water management. In this paper, the two-dimensional lattice Boltzmann method (LBM) is applied to investigate the two-phase behavior in gas diffusion layers with different porosity gradients under compression. Compression results in an increase in flow resistance below the ribs, prompting the appearance of the flow path of liquid water below the channel, and liquid water breaks through to the channel more quickly. GDLs with linear, multilayer, and inverted V-shaped porosity distributions with an overall porosity of 0.78 are generated to evaluate the effect of porosity gradients on the liquid water transport. The liquid water saturation values within the linear and multilayer GDLs are significantly reduced compared to that of the GDL with uniform porosity, but the liquid water within the inverted V-shaped GDL accumulates in the middle region and is more likely to cause flooding.

Electrical rock typing using Gaussian mixture model to determine cementation factor

Many studies have worked on the estimation of fluid saturation as an important petrophysical property in hydrocarbon reservoirs. Based on Archie's law, proper determination of cementation factor (m) can lead to accurate values of water saturation. Given that the m is mainly affected by electrical properties of rock, electrical quality index (EQI) can be used to estimate m through a novel rock typing technique. Despite the efficient applicability of EQI for the classification of rocks, with similar electrical behaviors, into distinct electrical rock types (ERTs), manual implementation of this method is time-consuming and gets excessively more difficult for larger datasets. In this work, a fast automated version of EQI methodology was presented. As a fuzzy clustering algorithm, Gaussian mixture model (GMM) was implemented on a large quantity of carbonate and sandstone samples to cluster them into distinct ERTs based on EQI values. To this end, 100 data points were randomly selected for testing purposes, and the remaining data points were used as training subsets for carbonate and sandstone samples. An innovative hybrid EQI-GMM approach was developed to determine the optimum number of clusters. Furthermore, results of two commonly-used criteria, namely Schwarz's Bayesian Criterion (BIC) and Akaike Information Criterion (AIC), showed that they fail to specify ERTs properly. The predicted values for m by the hybrid EQI-GMM approach were more accurate (RMSE is 0.0167 and 0.0056 for carbonate and sandstone samples, respectively) than outputs of the traditional Archie’s law (RMSE is 1.6697 and 0.1850 for carbonate and sandstone samples, respectively).

Determining local transport properties of gas diffusion layer land-channel regions via pore network modelling

Targeted, pre-determined values of spatially-resolved liquid water saturation is achieved in the pore networks of polymer electrolyte membrane (PEM) fuel cell gas diffusion layers (GDL). An inlet selection algorithm is presented, where the local saturation of the overall substrate, channel region, and land region match the prescribed input values (within a tolerance of 2% absolute error). With this algorithm, we conduct a novel, comprehensive characterization of the influence of local saturation on local oxygen transport properties using 1721 unique saturation conditions within the GDL. The oxygen transport properties of the GDL are significantly affected by the spatial distribution of liquid water. We find that liquid water accumulation in the channel region leads to an increase in the oxygen transport resistance in the channel region of the substrate and overall substrate. The channel region saturation is a better predictor of substrate transport properties than the substrate saturation alone. The correlation between the land region saturation and the oxygen transport resistance of the substrate is weak and depends on the spatial distribution of liquid water in the land region. Land region saturation only has a strong influence on the oxygen transport resistance in the land region of the substrate.

Characterization of Movable Fluid Distribution in Tight Oil Reservoirs by NMR and Centrifugation

The reservoir of Chang 7 Member of Yanchang Formation in the Ordos Basin is rich in tight oil resources, with well-developed micro-nanopore throats, strong heterogeneity, and complex fluid distribution characteristics. In this paper, a combination of nuclear magnetic resonance and centrifugation experiments is carried out to qualitatively and quantitatively analyze and evaluate the distribution characteristics of the movable fluid in Chang 7 reservoirs in Baibao Block. With different centrifugal forces, the NMR T2 spectrum characteristics of saturated water state and different centrifugal force state can be obtained, and the movable fluid distribution characteristics under the control of different centrifugal forces and different pore throat intervals can be obtained. The research results demonstrate that the NMR T2 spectrum of the Chang 7 tight oil reservoir in the study area presents a double-peak or triple-peak shape. With the increase of centrifugal force, the water saturation value of the corresponding sample gradually decreases. The overall movable fluid saturation ranged from 19.07% to 32.52%, with an average of 26.23% and a low degree of movability. The submicron (0.1~1 μm) and nanoscale (0.075~0.1 μm) pore throats were the main pore throat intervals controlling the movable fluid saturation of the studied samples, accounting for an average of 18.31% and 5.57%, respectively, and micron-scale pore throats ( r &gt; 1 μ m ) accounted for an average of 2.35% of the movable fluid distribution.

The rock typing of complex clastic formation by means of computed tomography and nuclear magnetic resonance

This study provides a new rock-typing approach for low-resistive and low-permeable clastic rocks. The approach includes integrated interpretation of routine core analysis data with microstructural characteristics, acquired from computed tomography (CT) and nuclear-magnetic resonance (NMR) data. The studied formation comprises siltstones in its bottom, which are replaced by sandstones in its top. Sandstones form the main part of the oil reservoir, whereas siltstones were originally considered as water-saturated. The reserves calculation was performed based on a single Archie equation for the whole formation. Despite on apparent water saturation and low permeability of the siltstones, incidental perforation showed considerable oil inflow from them as well. In order to delineate missed productive intervals within the low-resistive siltstones, we had to develop a new rock-typing approach, acknowledging rock multimineral composition, diversity of microstructures, a wide range of porosity, permeability, and residual water saturation values. Designed laboratory program included porosity, permeability, electrical resistivity measurements, capillary, NMR and CT tests. The experiments were performed on the same core samples that enabled reliable correlation between measured parameters. The joint interpretation of flow zone indicator, calculated as a function of porosity and residual water saturation, together with the results of petrophysical and microstructural measurements allowed reliable rock-typing of the clastic formation. It will serve as a petrophysical basis for identification of the missed productive intervals. The developed laboratory program and rock-typing algorithm can be implemented in other oilfields.