Reservoir Properties Research Articles

The Cambrian sedimentology and reservoir properties of the hybrid Abbottabad Formation in the Kotli area, Sub-Himalaya, Pakistan: insights into the Proto-Tethys paleoenvironment

The Cambrian sedimentology and reservoir properties of the hybrid Abbottabad Formation in the Kotli area, Sub-Himalaya, Pakistan: insights into the Proto-Tethys paleoenvironment

Physical Properties of High-Rank Coal Reservoirs and the Impact on Coalbed Methane Production

The physical characteristics of coal reservoirs are important factors affecting the occurrence status of coalbed methane, as well as key factors restricting the production capacity. Therefore, taking 3# coal in Qinnan region of China as the research object, based on the actual production data of 200 coalbed methane wells in the research area, experimental testing combined with simulation analysis was used to explore the physical properties of medium and high-order reservoirs and their impact on the occurrence and production of coalbed methane. The characteristics of coalbed methane reservoir formation and production capacity changes in the research area were revealed, and the factors restricting the production capacity of coalbed methane wells were calculated using the gray correlation analysis method. The results indicate that the micropores in the coal reservoir in the study area are well-developed, while the macropores and mesopores (exogenous fractures) are underdeveloped, the surface of the micropores is complex, and the connectivity of the micropores is poor, resulting in reservoirs with high gas adsorption characteristics and low permeability. The fractal characteristics of pores and fractures can reflect the permeability characteristics of reservoirs. Permeability is positively correlated with macropores (exogenous fractures) and mesopores, and negatively correlated with micropores. There is a positive correlation between permeability and productivity, and the reservoir in the study area has a stress-sensitive boundary. The main factors restricting productivity under the complex pore and fracture system of high-rank coal reservoir were identified, and the gray relational analysis method was used to evaluate the development effect of the research area. This study provides guidance for the development of coalbed methane production in high-rank coal reservoirs.

Temperature stability and enhanced transport properties by surface modifications of silica nanoparticle tracers for geo-reservoir exploration

Tracer tests are an important tool for characterizing and monitoring subsurface reservoir properties. However, they are limited both because of the tracer molecules constraining factors such as irreversible adsorption, retention, and degradations, i.e. interaction processes of fluorophore molecule with surrounding media resulting in a large variation in transport properties. Elaborate tests utilizing more than one tracer to distinguish time or location of injection are complex and interpretation is ambiguous because each tracer interacts differently. In this study, we present an approach to increase tracer stability and enhance the transport uniformity of different tracers, thus making tests utilizing multiple tracers simpler and more feasible. We present this concept of tracer multiplicity by encapsulating an anionic, cationic or amphoteric fluorophore inside mesoporous silica nanoparticle carriers coated with a protective titania layer. Upon encapsulation, increased thermal resistance and drastically lowered sorption affinity towards quartz sand was detected in batch and flow-through experiments. An additional advantage of the presented nanoparticle tracers over molecular tracers is their modularity, which is demonstrated by surface modifications and application of additives that greatly reduce sorption and increase recovery rates in the flow experiments. With the here presented concept of tracer multiplicity, we introduce a new approach for colloidal tracer design that has the potential to expand and enhance measurable parameters, measurement accuracy and simplicity of analysis.

Sedimentological and diagenetic facies of tight sandstones in lacustrine delta-front: A case study of the Jurassic Lianggaoshan Formation, eastern Sichuan Basin

In this study, taking the Jurassic Lianggaoshan Formation (J1l) tight sandstones in the eastern Sichuan Basin as an example, the types and well-logging responses of main sedimentological and diagenetic facies in the lacustrine delta-front are investigated based on summarizing the sedimentary characteristics and reservoir properties. Subsequently, further validation and application are conducted in the study area through machine learning. Research results show that the J1l lacustrine delta-front in the eastern Sichuan Basin mainly develops subaqueous distributary channels and mouth bar sand bodies, exhibiting typical densification reservoirs, with porosity and permeability distributed between 0.48% and 11.24% (av. 3.87%) and 0.0003–0.653 × 10−3 μm2 (av. 0.026 × 10−3 μm2), respectively. Strong compaction and strong cementation are the primary factors leading to densification, whereas chlorite coatings and weak dissolution play constructive roles in preserving some primary pores, creating a small amount of dissolution pores, and enhancing permeability. In terms of manifestation, the pore-throat content with a radius greater than 0.006 μm governs the reservoir quality. Furthermore, five types of diagenetic facies are identified in the J1l subaqueous distributary channels and mouth bars: strong compaction facies (Type I), strong cementation facies (Type II), chlorite-coating and intergranular pore facies (Type III), weak dissolution and intragranular pore facies (Type IV), and medium compaction and cementation facies (Type V). Overall, the thick and coarse-grained subaqueous distributary channels can be considered as the preferred exploration targets for tight oil and gas, with type III and type IV diagenetic facies being the most favorable reservoirs, characterized by well-logging responses of high AC and low GR, DEN, and RT. Based on the fine division of sedimentological and diagenetic facies, establishing well-logging interpretation models and then employing machine learning to achieve sweet spot reservoir prediction can provide valuable insights for tight oil and gas exploration in regions lacking core data.

Study on the Reservoir Characteristics of the Triassic Yanchang Formation in the Majiahe Area, Ordos Basin

This study thoroughly analyzes the petrological and physical properties of the Chang 4+5 and Chang 6 reservoirs of the Triassic Yanchang Formation in the Majiahe area of the Ordos Basin. The lithology in the study area is mainly composed of gray fine-grained feld-spathic sandstone, followed by medium to fine-grained and silt to fine-grained feldspathic sandstone. The overall petrological characteristics indicate low compositional maturity and high structural maturity, reflecting the complexity of the depositional environment. The reservoir properties exhibit extremely low porosity (very low to ultra-low porosity) and permeability (very low to ultra-low permeability), with significant heterogeneity in the reservoirs.

The influence of different diagenesis on the elastic properties of different shale lithofacies: a case study of the upper Permian Wujiaping formation in East Sichuan Basin, China

Understanding the impact of diagenesis on the elastic properties of organic-rich shale reservoirs is essential for evaluating unconventional hydrocarbon reservoirs and interpreting seismic data. Recent advancements in the exploration of the Permian Wujiaping Formation in the eastern Sichuan Basin indicate its potential to become a significant succession within the Sichuan Basin. However, the effect of different lithofacies in the Wujiaping Formation on shale elastic properties under varying diagenetic conditions remains unclear, hindering detailed reservoir interpretation. This study employs X-ray diffraction, thin section analysis, scanning electron microscopy, organic geochemistry, and dynamic elastic property tests to investigate the Wujiaping Formation shale. The results reveal three primary lithofacies types: argillaceous shale, mixed shale, and siliceous shale. Argillaceous shale, subjected to intense compaction, forms a dense rock framework of oriented clay minerals, characterized by low porosity (1.66%), low elastic wave velocity (4122.30 m/s), low elastic modulus (2174.59 m/s), and high Poisson's ratio (32.24 GPa). Mixed shale, dominated by carbonates and quartz, exhibits a rock framework formed through dissolution and cementation, with high elastic wave velocity (5196.54 m/s), relatively high elastic modulus (2975.86 m/s), and moderate Poisson's ratio (58.53 GPa). Siliceous shale, comprising biogenic quartz particles, shows strong resistance to compaction. During hydrocarbon generation, it develops abundant organic matter pores, resulting in the highest porosity (2.36%), high elastic wave velocity (5177.92 m/s), high elastic modulus (2975.86 m/s), and low Poisson's ratio (62.23 GPa). The significant differences in mineral composition and diagenetic processes across the lithofacies lead to distinct elastic properties. This study provides a rock physics framework for the detailed seismic prediction of "sweet spots" in the Wujiaping Formation shale reservoirs and offers new insights into characterizing the diagenesis of unconventional shale reservoirs using geophysical properties.

Problems and Countermeasures in the Water Injection Development Process of Strong Water Sensitive Sand Conglomerate Reservoir

Due to the unique physicochemical property of strong water sensitive glutenite reservoirs, a series of problems may occur during water injection development, seriously affecting production efficiency and economic benefits. This study analyzed the problems and their causes in the water injection development process, constructed a water injection optimization model based on machine learning algorithms, and rigorously verified and evaluated the performance of the model. The results show that the algorithm proposed in this article has achieved significant advantages in prediction accuracy, reducing prediction error by 28.26%, and maintaining a high recall. In addition, as the sample size increases, the algorithm in this article performs more stably. When facing complex reservoir environments and a large amount of data, this algorithm can provide more accurate and reliable prediction results, providing strong support for the optimization of reservoir water injection development process. The research results can provide an effective decision support tool for the field of petroleum engineering, which helps to improve the efficiency and economy of oil extraction, and promote the sustainable growth of the petroleum industry.

Assessment of geomechanical properties of Sakhalin shelf reservoirs based on modeling results

Background. Due to the complex tectonic structure of the Sea of Okhotsk shelf and intense geodynamic activity in this area, specialized technologies are required to study reservoir properties. In this work, we implement the technology of secondary permeability estimation using the Kirinskoye and Ayashskoye license blocks as an example. The research objects included structural and lithologic traps of different complexes. It was found that the Prisakhalin shelf, including the Kirinsky and Ayashsky license areas, is subject to the modern shear stress field with the sublatitude-oriented axis of maximum compression. This initiates the formation of a local stress field, launches changes in the degree of fracture openness, and determines the secondary porosity and permeability of rocks. 3D modeling allowed us to calculate predicted permeability for each stratigraphic horizon. A significant difference of secondary permeability in the upper and lower stratigraphic horizons is noted.Aim. To evaluate secondary filtration and capacitance properties of reservoirs by geomechanical modeling.Materials and methods. Geomechanical modeling to assess the filtration and capacitance properties of Sakhalin shelf reservoirs was carried out using the ROXAR software package.Results. This work allowed not only the filtration efficiency to be predicted, but also the processes occurring in the geological section of the shelf of the Sea of Okhotsk to be elucidated.

The Changing of Micromechanical Properties of Coal after Water Immersion: The Insight from Nanoindentation Test

The application of the hydrodynamic method has enhanced the extraction of coal bed methane (CBM). In this method, fracturing fluid rapidly penetrates the coal reservoir, altering its intrinsic pore structure and microscopic mechanical properties. These changes impact the properties of the coal reservoir and CBM depletion. It is, therefore, crucial to explore how these micro-characteristics evolve following water invasion. In this context, using nanoindentation tests, the microscopic characteristics of three coal samples were measured under dry conditions and at water saturations corresponding to 44% and 75% relative humidity. The influence of water immersion on the pore structure was also assessed using mercury injection experiments. Moreover, cluster analysis was used to categorize the extensive measured data into three sub-components: fractures (large pores), inertinite, and vitrinite, to investigate the impact of water saturation on microscopic properties. The findings indicate that cluster analysis is well-suited to these data, showing excellent agreement with porosity and maceral tests. The relationship between the elastic modulus and hardness of dry and wet coal samples varies across the sub-components. There is a notable dependency in the case of vitrinite, whereas water content tends to reduce this dependency. It is also found that water content negatively affects elastic modulus and hardness and reduces the anisotropy ratio. The mechanical properties of inertinite are highly responsive to water immersion, whereas vitrinite exhibits lesser sensitivity. The softening mechanisms of coal when immersed in water, such as calcite phase dissolution, swelling stress fracturing, and weakening of macerals, are identified. This study offers new perspectives on the impact of moisture on the alteration of micromechanical properties in coal.

Interwell interference model of horizontal wells in shale gas reservoirs based on multi-connected boundary element method

Due to the wide application of closely spaced multi-well horizontal pads for developing unconventional gas reservoirs, interference between wells becomes a significant concern. Communication between wells mainly occurs through natural fractures. However, previous studies have found that interwell communication through natural fractures is varied, and non-communication also appears in the mid and late stages of production due to natural fracture closure. This study proposes a boundary element method for coupling multi-connected regions for the first time. Using this method, we coupled multiple flow fields to establish dual-well models with various connectivity conditions of the stimulated reservoir volume (SRV) region. These models also take into consideration of adsorption and desorption mechanism of natural gas as well as the impact of fracturing fluid retention.The study found that when considering the non-communication of SRV regions between multi-well horizontal pads, the transient behavior of the targeted well exhibits a transitional flow stage occurring before the well interference flow stage. In addition, sensitivity analysis shows that the well spacing and production regime, as well as the connectivity conditions of the SRV region, affect the timing of interwell interference. Meanwhile, the productivity of the two wells, reservoir properties, and fracturing operations affect the intensity of interwell interference.

Complementary testing and machine learning techniques for the characterization and prediction of middle Permian tight gas sandstone reservoir quality in the northeastern Ordos Basin, China

In this study, an integrated approach for diagenetic facies classification, reservoir quality analysis and quantitative wireline log prediction of tight gas sandstones (TGSs) is introduced utilizing a combination of fit-for-purpose complementary testing and machine learning techniques. The integrated approach is specialized for the middle Permian Shihezi Formation TGSs in the northeastern Ordos Basin, where operators often face significant drilling uncertainty and increased exploration risks due to low porosities and micro-Darcy range permeabilities. In this study, detrital compositions and diagenetic minerals and their pore type assemblages were analyzed using optical light microscopy, cathodoluminescence, standard scanning electron microscopy, and X-ray diffraction. Different types of diagenetic facies were delineated on this basis to capture the characteristic rock properties of the TGSs in the target formation. A combination of He porosity and permeability measurements, mercury intrusion capillary pressure and nuclear magnetic resonance data was used to analyze the mechanism of heterogeneous TGS reservoirs. We found that the type, size and proportion of pores considerably varied between diagenetic facies due to differences in the initial depositional attributes and subsequent diagenetic alterations; these differences affected the size, distribution and connectivity of the pore network and varied the reservoir quality. Five types of diagenetic facies were classified: (ⅰ) grain-coating facies, which have minimal ductile grains, chlorite coatings that inhibit quartz overgrowths, large intergranular pores that dominate the pore network, the best pore structure and the greatest reservoir quality; (ⅱ) quartz-cemented facies, which exhibit strong quartz overgrowths, intergranular porosity and a pore size decrease, resulting in the deterioration of the pore structure and reservoir quality; (ⅲ) mixed-cemented facies, in which the cementation of various authigenic minerals increases the micropores, resulting in a poor pore structure and reservoir quality; (ⅳ) carbonate-cemented facies and (ⅴ) tightly compacted facies, in which the intergranular pores are filled with carbonate cement and ductile grains; thus, the pore network mainly consists of micropores with small pore throat sizes, and the pore structure and reservoir quality are the worst. The grain-coating facies with the best reservoir properties are more likely to have high gas productivity and are the primary targets for exploration and development. The diagenetic facies were then translated into wireline log expressions (conventional and NMR logging). Finally, a wireline log quantitative prediction model of TGSs using convolutional neural network machine learning algorithms was established to successfully classify the different diagenetic facies.

Time-lapse full-waveform permeability inversion: A feasibility study

Time-lapse seismic monitoring necessitates integrated workflows that combine seismic and reservoir modeling to enhance reservoir property estimation. We present a feasibility study of an end-to-end inversion framework that directly inverts for permeability from multiple prestack time-lapse seismic data sets. To assess the method's robustness, we design experiments focusing on its sensitivity to initial models, potential errors in modeling, and crosstalk during multiparameter inversion. Our study leverages the publicly available Compass model to simulate CO2 storage in saline aquifers. This model is derived from well and seismic data from the North Sea in an area that is currently considered for geologic carbon storage.

Coalbed methane reservoir properties assessment and 3D static modeling for sweet-spot prediction in Dahebian block, Liupanshui Coal field, Guizhou Province, southwestern China

Guizhou Province has many multi-layer, thin-thick coal seams; however, complex geology, incomplete reservoir characterization, and sweet-spot selection technology prevent large-scale coalbed methane (CBM) development. This study evaluates the CBM reservoir properties within the Dahebian block using logging data, coal sample analysis, and well-testing data and develops a 3D static reservoir properties model to analyze their spatial and vertical propagation. A sweet spot evaluation model was established using a multi-level fuzzy method based on 9 parameters extracted from a 3D static reservoir properties model. The coal measure has 22 coal seams, and seams >2 m thick have 2 or 3 thin non-coal layers intercalated. Coal seams 1#, 7#, and 11# are thin to thick, deeply buried, widely distributed, and have high gas content and saturation. Undeformed and cataclastic coal predominates the coal seam 1# and 7#, whereas coal seam 11# is dominated by cataclastic and granulated coal. The southern and central parts of coal seam 7# and 11# have less tectonically deformed coal (TDC). Coal seams 1# and 7# have low permeability relative to seam 11# and are localized, while coal seams 11# have high permeability, are extensively distributed, and contain substantial gas concentrations. Comparative analysis of evaluation scores and CBM production statistics shows that high scores indicate sweet spots for CBM development. Sweet-spot potential was classified as high, medium, and low. Scattered sweet spots are found in single layers, while combined development (1# + 7#+11#) reveals a wider high-potential area in the south-central region. This area, featuring deep, thick coal seams, high permeability, gas saturation, reservoir pressure, and low TDC proportion, indicates significant development potential. This study validates CBM development statistics, identifies future development areas, and guides the development of geologically complex Guizhou CBM.

Enhancement Petrophysical Properties of Carbonate Reservoirs Using Plasma Channel Technology, Case Study: Yamama Formation, South of Iraq

Carbonate reservoirs are significant hydrocarbon productions, but their complex and heterogeneous nature often poses challenges in maximizing oil and gas recovery. Traditional methods for enhancing petrophysical properties have shown limited success in carbonate formations. However, new advancements in Plasma Channel Technology have shown promising results in improving the reservoir's petrophysical properties. The application of Plasma Channel Technology is considered as a novel approach to enhance the petrophysical properties of carbonate reservoirs. Plasma channel technology involves the controlled application of high-voltage electrical discharges to create conductive channels (new porosity) within the reservoir units. These channels serve as preferential pathways for fluid flow (permeability) and facilitate enhanced oil and gas recovery. The main objective of this study is to show the key aspects of the enhancement of the Yamama reservoir properties using Plasma Channel Technology minimizes the need for chemical additives to reduce operational costs and environmental impact. Therefore, Yamama Formation is studied in two oil wells Snd-1 and Snd-2, six core samples from reservoir units within the Yamama succession were studied to determine porosity using a Scanning Electron Microscope which provides valuable insights into their internal structure and porosity characteristics in these samples. A comparison had been done between porosities within rock samples before and after application of Plasma channel technology, where the porosity was ranging from micropores (10 nm) to mesopores (10-50 nm) in some samples before voltage electrical discharges, while it reached mesopores (20-50 nm) to macropores (more than 500 nm) after voltage electrical discharges.These pores have been increased in size if there was higher voltage which means enhancement in the petrophysical properties in the reservoir.

Some features of local structures and their reservoir properties in the South Caspian Basin

Some features of local structures and their reservoir properties in the South Caspian Basin

Petrophysical Characteristics of Mauddud Formation in Selected Wells of Ratawi Oilfield, Southern Iraq

The Mauddud Formation is the most widespread Lower Cretaceous formation in Iraq, deposited along the NE margin of the Arabain Palte. The formation is widely distributed, covering nearly the entire territory of Stable and Unstable Shelf units. The study area is located in the Zubair subzone of the Mesopotamian zone within the Stable Shelf unit, approximately 70 km northwest of Basrah in southern Iraq. The main goal of this study is to evaluate the petrophysical characteristics of Mauddud Formation in the five wells (Ratawi-2, Ratawi-4, Ratawi-5, Ratawi-17, and Ratawi-19) in the Ratawi oilfield, southern Iraq. Open hole log analysis was utilized, and a series of calculations were applied to evaluate the reservoir properties, such as porosity, water saturation, and volume shale, that control the reservoir quality. The N-D cross plot diagram shows that limestone is the dominant lithology, and few shale contents is present in the upper and lower parts of the formation, while it is noticed that the volume of clay is constant throughout the formation in most of the wells, indicating that the formation is clean. Seven zones (A to G) have been identified and evaluated, depending mainly on full set logs to determine the most productive ones. Zones B, D, and F are classified as good reservoir zones with an average porosity of 21% and water saturation of 25%. A and C zones show reservoir and non-reservoir zones with porosity of 10% and water saturation of 40%. Finally, the remaining zones represented by E and G are classified as non-reservoir zones with a very low porosity of less than 4% and fully water-saturated.

Diagenesis of Cenomanian–Early Turonian and the Control of Carbonate Reservoirs in the Northern Central Arabian Basin

The carbonate reservoirs of Cenomanian–Early Turonian in the northeastern Central Arabian Basin hold considerable oil reserves and are great contributors to oil production. Diagenesis have a great impact on carbonate reservoir petrophysical properties, microstructure, and heterogeneity. By integrating cores, cast thin sections, regular core analysis, CT, and isotopes, this study provides an improved understanding of diagenesis in the Cenomanian–Early Turonian and its effect on carbonate reservoirs. The results showed that three diagenetic environments were identified in the Cenomanian–Early Turonian based on texture, structure, cement, crystal form, and crystal size, which were marine environment, meteoric environment, and burial environment. Six diageneses were identified based on residual bioclastic, secondary pores, calcite quantity, dolomite size, and stylolite, namely dissolution, cementation, micritization, dolomitization, compaction, and pressure solution. A micritization model in high energy sediment, a dolomitization model in burrows, and a comprehensive diagenetic model were established. It concluded that dissolution during meteoric environment is most favorable to reservoir physical properties, while cementation is least favorable. The cement content controls the microstructure and petrophysical property. Micritization is detrimental to the petrophysical properties, and the micrite it forms are distributed in the interparticle pores, reducing the reservoir property deposited in high energy environment. Dolomitization is less developed in substrate but widely developed in burrows, which result in the physical properties of the burrows being higher than those of substrate. Compaction and pressure solution have a negative impact on reservoir physical properties.

Dynamic prediction of fracture propagation in horizontal well hydraulic fracturing: A data-driven approach for geo-energy exploitation

Accurate and efficient prediction of hydraulic fracturing fracture propagation is of utmost importance for unconventional reservoir development. Traditional numerical simulation methods require specialized domain knowledge and technical expertise, and machine learning approach can be an alternative predictive tool for fracture propagation. Additionally, existing neural networks cannot be directly applied to hydraulic fracturing scenarios influenced by multiple coupled factors. Thus, this study presents an innovative approach, “AE-ATT-ConvLSTM”, that integrates an additional Convolutional Layer, Autoencoder, and an Attention Mechanism Feature Fusion Layer into the architecture of a Convolutional Long Short-Term Memory (ConvLSTM) sequential image prediction network. This approach aims to predict fracture propagations in different fracturing stages of horizontal wells. The proposed model is trained on a sample dataset consisting of 5000 instances of hydraulic fracturing in horizontal wells. The dataset includes crucial data such as fracture propagation images, wellbore perforation images, natural fracture images, pumping schedules, and reservoir properties. The model achieves remarkable results, with an MSE less than 15 × 10−5, a maximum SSIM of 0.93, and an average FMAE less than 48. The research findings demonstrate that this method significantly enhances prediction efficiency and provides new insights for predicting fracture morphology and optimizing fracturing design.

Depositional architecture of early rift non-marine systems and implications for reservoir development: Oligocene to Miocene Al Wajh Formation, Midyan Basin of Red Sea, Saudi Arabia

Exhumed early rift alluvial fan and braided fluvial fan systems are rare and consequently understanding facies distribution, stratal architecture, reservoir connectivity, and controls on stratigraphic development of these systems is quite difficult. The outcrops of early Oligocene to early Miocene Al Wajh Formation in the Red Sea region of Saudi Arabia provide an opportunity to investigate the depositional architecture and reservoir potential of an early rift alluvial to fluvial system. Eleven lithofacies (F1-F11) and four facies associations (alluvial fan facies association (FA1), braided fluvial fan facies association (FA2), floodplain facies association (FA3) and delta front facies association (FA4)) are identified in four subbasins (Maqna 1–2, Sukk and Ifal), suggesting deposition in an alluvial-braided fluvial fan system. FA1 (36–100%) and FA4 (9–13%) have higher relative proportion and widely distributed in the northern subbasins (Sukk and Ifal subbasins) while the relative proportion of FA2 (50–82%) and FA3 (18%) increases towards southern subbasins (Maqna-1 and Maqna-2 subbasins). Distribution of facies associations, relative reduction in the clast diameter, and general southward paleoflow direction suggest that the northern subbasins (Sukk and Ifal) represent the proximal settings and southern subbasins represent medial (Maqna-1 subbasin) and distal settings (Maqna-2 subbasin) of a large alluvial-braided fluvial fan environment. Stratal architecture of proximal conglomeratic channel deposits highlight that despite reasonable thickness and spatial connectivity (several meters), these deposits may have marginal reservoir quality because of poor sorting and high matrix content. Sandstone beds occurring in medial settings have a higher potential to act as hydrocarbon reservoirs by displaying excellent reservoir properties on the account of their significant thickness (up to few meters), coarse grain sizes, better sorting, considerable spatial connectivity (10s of meters) and lower proportion of interbedded mudstone.

Study of the contact angle and roughness effects on mercury intrusion porosimetry (MIP) analysis in natural/real carbonate rocks using massive pure minerals and synthetic carbonate rocks

Studying pore networks in rocks is critical for understanding reservoir properties, with mercury intrusion porosimetry (MIP) being a key laboratory method. MIP involves capillary intrusion of mercury, with intrusion pressure (P) related to capillary diameter (d) by the Washburn equation, incorporating mercury properties like contact angle (θ) and surface tension (γ). While a constant contact angle of 140° is typically assumed for MIP, it can vary based on rock mineralogy and surface roughness. This study aims to analyze how contact angle variations and surface roughness affect MIP analysis of carbonate rocks. Initially, contact angle data was obtained for calcite, dolomite, and quartz with varying roughness levels. Synthetic rocks were then constructed using these minerals. MIP was performed using the typical 140° contact angle and a calculated contact angle from the Cassie model, which considers surface composition fraction. Natural rock MIP analysis followed, with contact angles varying due to mineral composition and roughness. The study found higher contact angles than the standard 140°, affecting pore size distributions up to 30%. Natural rock pore network curves were adjusted based on synthetic rock data analysis. These findings emphasize the need for accurate contact angle selection in MIP for precise pore distribution analysis and contribute to the further study of carbonate rocks.