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Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

Low-contrast oil reservoirs have a complicated origin story that frequently results from the interaction of several different factors. The low-contrast oil reservoirs in the Daqing Oilfield's SaPu intercalation in the Longxi Region are the main subjects of this study. This work investigates the petrophysical origins of these low-resistivity oil reservoirs through a series of carefully planned petrophysical experiments. The results showed that the main determinants of the low-contrast oil reservoirs in the SaPu intercalation were the conductivity of clay minerals and a high irreducible water saturation. A low clay conductivity had a significant effect, resulting in a significant reduction in the formation resistivity, even in circumstances with a low porosity and a low formation-water salinity. Moreover, the results from the NMR tests revealed that the irreducible water saturation in the core samples primarily ranged from 0.6 to 0.8, suggesting a significant prevalence. This work provides strong petrophysical indices for evaluating low-resistivity oil reservoirs in the SaPu intercalation and useful information for the petrophysical evaluation of similar reservoirs. [ABSTRACT FROM AUTHOR]

The study of pore structure requires consideration of important factors including pore throat size, pore radius composition, and pore-throat configuration. As the nuclear magnetic resonance (NMR) experimental results contain rich information about pore structures and fluid occurrence states, this study investigated the pore structures of the tight sandstone reservoirs of the Shanxi Formation in the Daning-Jixian area, eastern Ordos Basin. Firstly, by making the inverse cumulative curve of the NMR T2 spectrum coincide with the capillary pressure curves which were obtained by the mercury injection capillary pressure (MICP) technique, this study derived a conversion coefficient that can be used to convert the NMR T2 spectrum into the pore throat radius distribution curves based on the NMR experimental results. Subsequently, we determined the pore radius intervals corresponding to irreducible water distribution using the NMR-derived pore radius distribution curves. Finally, the NMR T2 distribution curves based on the fractal theory were analyzed and the relationships between fractal dimensions and parameters, including permeability, porosity, reservoir quality index (RQI), flow zone indicator (FZI), irreducible water saturation, RT35, and RT50, were also discussed. The NMR-derived pore throat radius distribution curves of the study area are mainly unimodal, with some curves showing slightly bimodal distributions. The irreducible water mainly occurs in small pores with a pore radius less than 100 nm. As the permeability decreases, the contribution rate of small pores to the irreducible water gradually increases. The NMRbased fractal dimensions of pores show a two-segment distribution. Small pores have small fractal dimensions and are evenly distributed, while large pores have large fractal dimensions and complex pore structures. The fractal dimension of large pores (Dmax) is poorly correlated with porosity but strongly correlated with FZI, RQI, RT35, and RT50. These results indicate that large pores are the main pore zones that determine the seepage capacity of the reservoirs. Additionally, there is a certain correlation between Dmax and the irreducible water saturation. [ABSTRACT FROM AUTHOR]

Petrophysical properties are used to characterize a reservoir. Hence, this study evaluates petrophysical properties of the Sapele shallow field in the Niger Delta Area of Southern Nigeria with the aid of log data such as gamma-ray, density, neutron, and resistivity. Quantitative properties including shale volume, porosity, permeability, Irreducible water saturation, formation factor, water saturation, and hydrocarbon saturation were carried out using the well logs. One oil-bearing reservoir was identified across the field. Computed petrophysical parameters across the reservoir provided average porosity ranging from 0.30 to 0.36, permeability values range from 2707.9 to 3721.9 milli Darcy (mD) and the average hydrocarbon saturations are 0.51, 0.42, 0.47, 0.46, 0.47, and 0.49 for well 21, 22, 29, 30, 31, and 32 respectively. The field covers an area extent of 17137.18 acres. [ABSTRACT FROM AUTHOR]

Petrophysical properties are used to characterize a reservoir. Hence, this study evaluates petrophysical properties of the Sapele shallow field in the Niger Delta Area of Southern Nigeria with the aid of log data such as gamma-ray, density, neutron, and resistivity. Quantitative properties including shale volume, porosity, permeability, Irreducible water saturation, formation factor, water saturation, and hydrocarbon saturation were carried out using the well logs. One oil-bearing reservoir was identified across the field. Computed petrophysical parameters across the reservoir provided average porosity ranging from 0.30 to 0.36, permeability values range from 2707.9 to 3721.9 milli Darcy (mD) and the average hydrocarbon saturations are 0.51, 0.42, 0.47, 0.46, 0.47, and 0.49 for well 21, 22, 29, 30, 31, and 32 respectively. The field covers an area extent of 17137.18 acres.

The article is devoted to the problem of evaluation of oil displacement coefficient. Determination of oil displacement coefficient is essential stage for estimation of recoverable reserves, feasibility study of oil recovery factor and control of field development. Complexity of its laboratory determination is caused by labor intensity and duration of a process. When the number of cores is not enough for flow experiments or absent oil recovery factor is evaluated either similarly to neighbor fields or by analytical dependencies that are important to obtain. During the generalization and analysis of a significant amount of experimental data the authors developed a method for estimation of oil displacement coefficient without its laboratory determination. A proposed method is based on use of data from previous studies to built statistical models for estimation of displacement coefficient using linear step-by-step regression and discriminant analysis. In order to implement the method along with oil viscosity, knowledge of reservoir parameters such as porosity, permeability, irreducible water saturation and bulk density of a rock, determined by conventional core studies, is required. The main stages of implementation of the method for Visean clastic deposits of the Bashkir arch and Solikamsk depression of the Perm Region are presented. Results of implementation of the method for Bashkir carbonate deposits of the indicated tectonic elements are presented as well. Analysis of initial data allow establishing that there are classes of values for which regression equations are statistically justified. According to the equations model and experimental values of the displacement coefficients are very close to each other. It was concluded based on parameters of the equations that there is abnormal influence of initial oil saturation on the displacement coefficient. It is shown that for reservoirs of low flow characteristics a displacement coefficient is determined by their capacitive properties.

Irreducible water saturation (S wir) is an important parameter in reservoir evaluation that can affect hydrocarbon saturation, permeability prediction models and estimation of original oil in - place. The S wir is usually obtained from capillary pressure data. In this study, routine and special core analyses for sandstone reservoirs in four wells were used to investigate the relationship between irreducible water saturation and the petrophysical properties of the reservoir rocks. The results indicated that the magnitude of S wir is controlled by a complex relationship of reservoir rock wettability, reservoir quality, clay content, clay mode of distribution, and capillary pressure. Reservoir rock wettability can obscure the effect of other factors in the case of oil–wet rocks. On the other hand, irreducible water saturation from published data were used together with the studied four wells data, providing 110 sandstone samples covering different geologic ages and facies, to examine the applicability of the traditional empirical models that were commonly used in S wir prediction as well as to introduce a new simple equation by which S wir can be predicted. The study indicated that the Timur equation gave the best applicable empirical model to predict S wir. The study indicated also that the flow zone indicator can slightly improve the prediction strength of the S wir. Using other parameters characterizing capillary pressure curves such as displacement pressure and Swanson parameter didn't improve the relationship prediction strength. • A new equation was proposed to predict irreducible water saturation as a function in flow zone indicator. • Wettability is the major role in determination of values of the irreducible water saturation. • Effects of reservoir quality, clay content and capillary pressure on S wir can be obscured by the effect of rock wettability and fluid properties. [ABSTRACT FROM AUTHOR]

Relatively new direction for geological properties study in petroleum geology nowadays is the use of X-ray tomography. The basis of this method is X-ray rock density study. This paper shows the results of possible X-ray tomography applications while studying petrophysical properties of carbonate reservoir plugs on example of several oil fields in Perm region. The microfocus system of X-ray control with computer tomography Nikon Metrology XT H 225 and software AvizoFire 7.0 were used. The cylinder samples with diameters of 30 and 10 mm and cubic samples with a side length of 5 mm were used in the study. The results of X-ray tomography represent 2D-slices of lengthwise and crosswise sample cross-section, 3D-model of cavities, consolidation areas and initial oil saturation distribution as well as graphs of pore and irreducible water saturation versus sample height and histograms of pore diameters. The study of cavities and consolidation areas distribution in the samples allowed to type core depending on its cavity structure. Analysis of porosity evaluation of the samples with different diameters that were made from the one pies of core showed that correlation coefficient was 0.77. Such relatively low coefficient could be explained by significant heterogeneity of core even in one lithotype. During the irreducible water saturation determination four radiographic solutions were tested. It was noticed that irreducible water does not exist in the large voids (cavities, cracks, big pores). Best results were obtained for NaI and LaCl3·3H2O solutions. Presented in this paper results allow obtaining most authentic 3D distribution of pore space and fluid saturation during futhure X-ray tomography study of carbonate deposits.

Abstract Zones with low resistivity low contrast (LRLC) are usually overlooked due to the absence of high-end well logging techniques in the older oil/gas fields. The Nyalau Formation outcrop (stratigraphically equivalent to offshore cycles I and II) from Sarawak, offers a good opportunity to identify and characterize LRLC zones through integrated approaches. Seven facies of the Nyalau Formation had been identified, which are: 1) low angle cross-bedded sandstone (CBSS), 2) laminated sandstone (LSS), 3) heterolithic sandstone (HSS), 4) bioturbated sandstone (BSS), 5) clay-rich sandstone (CSS), 6) mudstone (MS), as well as 7) trough CBSS (TCBSS). Apparent resistivity was determined for brine (60 kpm) saturated core plugs at a temperature of 75 °F by employing the sample core induced polarization technique. The measurement of resistivity was calibrated based on offshore salinity, as well as surface and subsurface temperature of the Sarawak. The geological and petrophysical characteristics were analyzed through field observations and lab analyses. The findings of the study revealed that the cutoff value of resistivity found at LRLC zones in Nyalau Formation was 12.6 Ω-m. Accordingly; LSS, BSS, and CSS facies appeared to derive from LRLC zones. The main causes that generate such LRLC zones are laminations, thin bedding, bioturbation, and clay minerals. The dominant effect portrayed by mixed layers of illite/smectite and smectite in LRLC zones could be attributed to their high cation exchange capacity (CEC). Two varying resistivity trends were discovered based on the variances detected in clay types for different facies. A negative correlation was found between resistivity and porosity within high resistivity zones, while a positive relationship within the LRLC zones. Disparity in the resistivity-porosity correlation is deduced to be associated with clay mineralogy. This study suggests that LRLC zones are expected to be present in shallow marine clastic reservoirs of offshore cycles (I and II), where the offshore reflects Nyalau Formation. Highlights • A detailed investigation of shallow marine clastic reservoir (Nyalau Formation) carried out to identify LRLC zones. • This is the first study for identification and characterization of LRLC zones at outcrop level. • The resistivity of zones had effected by clay type, sedimentary features, and petrophysical parameters (e.g. pore size). • The effect of total clay content and distribution altered the reservoir properties in a significant way. [ABSTRACT FROM AUTHOR]

The prediction of porosity is achieved by using available core and log data; however, the estimation of permeability is limited to the scare core data. Hence, porosity and saturation data through the framework of flow units can be used to make an estimation of reservoir permeability. The purpose of this study is to predict the permeability of a carbonate gas reservoir by using physical-based empirical dependence on porosity and other reservoir rock properties. It is emphasized that this new relationship has a theoretical background and is based on molecular theories. It is found out that if rock samples with different types are separated properly and samples with similar fluid-flow properties are classified in the same group, then this leads to finding an appropriate permeability/porosity relationship. In particular, the concept of hydraulic flow units (HFU) is used to characterize different rock types. This leads to a new physical-based permeability/porosity relationship that has two regression constants which are determined from the HFU method. These coefficients, which are obtained for several rock types in this study, may not be applicable to other carbonate rocks; but, by using the general form of the model presented here, based on the HFU method, one may obtain the value of these coefficients for any carbonate rock types. Finally, we used the data of cored wells for the validation of the permeability results.

Irreducible water saturation value is an indication of total volume of oil and water producible from a reservoir. It also influences the production rate from that reservoir. The irreducible water saturation for some Kwale sands were analysed in this work using Timur, Tixier and Coates-Dumanoir models. It was discovered that the Timur and Tixier models gave reasonable irreducible water saturation values with the Timur values being closer to the water saturation values and hence of more accurate values. The Coates-Dunamior model gave almost 100% Swirr values but this is unrealistic value for any oil reservoir, except for rocks in water zone with initial water saturation of almost 100%. Moreover, porosity for the different sands were analyzed to obtain a relationship such that porosity is function of water saturation only for each sand. It was also observed that porosity-water saturation relationship is a polynomial equation of degree 2 or 3 for the Kwale sands. Permeability was also anayzed as a function of porosity. For Kwale sand C that has average porosity closest to the most common porosity in Kwale reservoir, the model equations obtained are φ = 0.0054Sw² - 0.6538Sw + 36.331 for porosity-water saturation; K=95000φ²-34100φ+3058 for permeability-porosity relationship and Swirr=-446.5φ²+162.4φ-14.09 for the irreducible water saturation- porosity relationship. [ABSTRACT FROM AUTHOR]

The maximum pore space available for gas storage in oilsand reservoir was analyzed in this research. This maximum pore space is equal to the maximum volume of water that can be flushed out of the pore space. This corresponds to the difference between the initial water volume and irreducible water volume. Two sets of samples were obtained, the well-mixed and the poorly mixed samples. Three samples were obtained for each of the sets of samples. The ratio of the bitumen to sand was 60:40, 70:20 and 80:20 percent respectively. It was observed that no matter the bitumen content of the oilsand samples used, the irreducible water saturation obtained was 50%. Among the six samples used only two samples followed the expected 2-phases of decline drying curves. These were the well-mixed 60:40% bitumen-sand sample and the poorly mixed 80:20% bitumen sand sample. For the remaining four samples, there were only one phase of decline drying rate which is regarded as the last phase of decline drying curve for the four samples and was therefore taken as the Swirr of the corresponding core sample. It was observed that the obtained porosity values for the samples followed the expected trend for well-mixed samples since porosity is expected to increase with increasing sand content as bitumen is non-porous. The porosity for the well-mixed oilsand samples ranges from 0.0179 and 0.0134 for 60% to 80% bitumen content. For the poorly mixed sample, observed porosity does not follow any reasonable trend. This is expected because the effective porosity for poorly-mixed sample cannot be predicted based on the sand content of the oilsand due to high probability of formation of localized or non-interconnected pore spaces. [ABSTRACT FROM AUTHOR]

Irreducible water saturation is one of the fundamental parameters in characterizing hydrocarbon formations, playing key role in volumetric and recovery calculations and permeability definition within a reservoir. The determination of the reservoir permeability using the irreducible water saturation in a shaly sand transition zone has been problematic due to the presence of the bound water saturation. In this research, a model was developed based on the Coates and Dagan permeability model formulation using the dual water model parameters. In this model formulation using the three models, a sensitivity coefficient for conditioning the permeability field at the transition zone was introduced. The sensitivity factor is a quotient function of bound water saturation and the total water saturation. The localized nature of the well data in the determination of the depositional architecture (porosity and permeability) were extrapolated away from or interpolated between acquisition locations using the areal coverage provided by seismic data. The analysis of the well information from the Kolmani River showed that the hydrocarbon lies at depth between 2071m and 2194m (Cenomenian-Turonian Yolde formation). The acoustic map within the reservoir shows the occurrence of dense uniform marine shales and sandstones. It also shows the depositional process has been uniform and sequential. High density clastic materials were also discovered within the reservoir. The permeability results obtained by equating the bound water and total water saturations to the irreducible water saturation gave the 26mD and 16mD as the upper (clean sand) and lower (pure shale) limits of the effective permeability values for the reservoir. The result obtained using the new model showed that the effective permeability is 21mD within the transition zone. Other petrophysical results showed that the reservoir has an effective porosity of 20% and effective water saturation of 12%. Based on these reservoir results, it is understood that the well is highly compact and will not flow during production. • This paper presents a new model for shaly sand formation permeability evaluation within the transition based on the application of the Dual water model formation parameters such as: water saturation and porosity to the geometric model of Dagan (1979) based on the utilization of the Coates permeability model (1974). • The resulting model for the shaly sand formation represents a significant improvement in the determination of the various boundary values permeability within the shaly sand reservoir formation. • The research is a work on Gongola arm of the upper Benue Trough within the Nigerian Frontier Inland Sedimentary Basin (NFISB). • The model has helped to delineate the contribution of authigenic clay minerals whose open structure is able to trap water and generally affect permeability. • The boundary value problems of determining permeability within the transition zone has been formulated. • The 21mD value obtained is called the transition zone permeability at the prospect horizon and it falls within the range observed by previous resersers. [ABSTRACT FROM AUTHOR]