Mercury Injection Capillary Pressure Data Research Articles

Augmenting X-ray micro-CT data with MICP data for high resolution pore-scale simulations of flow properties of carbonate rocks

Pore-scale modeling is essential in understanding and predicting flow and transport properties of rocks. Generally, pore-scale modeling is dependent on imaging technologies such as Micro Computed Tomography (micro-CT), which provides visual confirmation into the pore microstructures of rocks at a representative scale. However, this technique is limited in the ability to provide high resolution images showing the pore-throats connecting pore bodies. Pore scale simulations of flow and transport properties of rocks are generally done on a single 3D pore microstructure image. As such, the simulated properties are only representative of the simulated pore-scale rock volume. These are the technological and computational limitations which we address here by using a stochastic pore-scale simulation approach. This approach consists of constructing hundreds of 3D pore microstructures of the same pore size distribution and overall porosity but different pore connectivity. The construction of the 3D pore microstructures incorporates the use of Mercury Injection Capillary Pressure (MICP) data to account for pore throat size distribution, and micro-CT images to account for pore body size distribution. The approach requires a small micro-CT image volume (7–19 mm3) to reveal key pore microstructural features that control flow and transport properties of highly heterogeneous rocks at the core-scale. Four carbonate rock samples were used to test the proposed approach. Permeability calculations from the introduced approach were validated by comparing laboratory measured permeability of rock cores and permeability estimated using five well-known core-scale empirical model equations. The results show that accounting for the stochastic connectivity of pores results in a probabilistic distribution of flow properties which can be used to upscale pore-scale simulated flow properties to the core-scale. The use of the introduced stochastic pore-scale simulation approach is more beneficial when there is a higher degree of heterogeneity in pore size distribution. This is shown to be the case with permeability and hydraulic tortuosity which are key controls of flow and transport processes in rocks.

Optimization of gas saturation calculation model for deep clastic reservoirs under strong compression stress

The interpretation model for gas saturation in deep clastic reservoirs subject to intensive extrusion stress relies predominantly on experimental petrophysical data and the expanded Archie equation. Nonetheless, these methodologies may not consistently yield optimum results. Specifically, when subsurface pressure impacts formation resistivity, the resulting curve values exhibit substantial elevations, leading to significant inaccuracies in the precise estimation of gas saturation from resistivity logging data. Consequently, the evaluation of logging interpretations becomes a complex undertaking. This paper aims to comprehensively assess gas saturation in deep clastic reservoirs from both electrical and mechanical perspectives. To achieve this goal, we employ a multifaceted approach encompassing the Archie formula, the stress-corrected variable cementation index saturation model, and the resistivity-corrected saturation model. Through rigorous theoretical analysis and the utilization of simulated experimental data, a quantitative relationship equation between resistivity and stress difference has been established. Building upon this fundamental groundwork, an innovative resistivity-corrected saturation calculation model has been proposed. In comparison to the two alternative models, the new model exhibits enhanced accuracy in calculating gas saturation, as it is less influenced by extrusion stress and gravitational compaction. Furthermore, it demonstrates better consistency with core mercury injection capillary pressure data in determining gas saturation. The findings of this research provide valuable insights for the effective evaluation of deep clastic reservoirs, offering a robust framework for advancing the understanding of gas saturation in the face of complex geological and geophysical challenges.

Implementing pore size distribution into saturation height function modelling of reservoir rock types: A case study on a carbonate gas reservoir

The accurate determination of saturation-height functions for modeling multiphase fluid flow in porous media is critical for applications, such as hydrocarbon recovery and subsurface CO2/H2 storage. The challenges associated with water saturation distribution in carbonate reservoirs arise from their inherent heterogeneity and complex pore systems. Addressing such challenges, this study aims to introduce a robust saturation-height function model that considers a non-linear relationship between capillary pressure and saturation, leading to more reliable estimates of fluid saturations. To achieve this, modifications were performed on a saturation height model based on the relationship between porosity, permeability, and pore size distribution (PSD). First of all, the capillary pressure model implemented in the previously introduced PSD-based approach was replaced by a model suitable for heterogeneous reservoirs, fitting the available mercury injection capillary pressure (MICP) data with higher accuracy. Additionally, the derivation of the relations between the optimum pore throat radius and matching parameters of the capillary pressure model was conducted by finding the best correlation among all the available data in the previous approach. For the first time in this study, considering the resemblance in rock properties like capillary pressure and PSD within each rock type, individual correlations among these parameters were established for each reservoir rock type. The predicted saturation height model was cross-checked against the log and core-derived saturation heights, demonstrating a high level of consistency, particularly along the gas-saturated regions. The obtained results were also compared with the conventional saturation height models, including the Leverett J-Function, Johnson's method, and Cuddy's approach. The significance of the modifications was underscored through a comparison of results with those achieved by the previous approach in which the rock typing was ignored. Although the PSD method, which ignored rock types, exhibited high consistency with log data, our modifications yielded far better predictions by improving the coefficient of determination from 0.68 to 0.84.

Pore-Type Characterization and Reservoir Zonation of the Sarvak Formation in the Abadan Plain, Zagros Basin, Iran

Carbonate reservoirs are characterized by their complex depositional–diagenetic history and, consequently, intricate pore networks. In this study, pore types and reservoir zones of the Sarvak Formation, which is the second most important oil reservoir in Iran, are investigated by integrating core, thin-section, porosity–permeability, scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP) data. Depositional, diagenetic, and fracture pores are identified in macroscopic to microscopic scales. Frequency analysis of pore types revealed that diagenetic pores, including vuggy, moldic, intercrystalline, and fracture pores, formed the majority of pore spaces of the Sarvak Formation. They are dominantly recorded in the regressive systems tracts of both the Cenomanian and Turonian sequences, just below the paleoexposure surfaces. Away from the disconformities, there are two general trends regarding the pore-types distribution: (a) grain-supported facies of shoal and talus settings with dominant primary (depositional) pores including interparticle, intra-skeletal, and growth-framework pores, which are concentrated in the middle part of the formation, and (b) microporous mud-dominated facies with various types of primary and secondary pore types in the TSTs of third-order sequences, especially in the lower part of the Sarvak Formation. Stratigraphic modified Lorenz plot differentiated reservoir, speed, barrier, and baffle zones in this formation. Depositional–diagenetic characters, petrophysical properties, and dominant pore types are defined for each zone in a sequence stratigraphic framework.

Integrated approach for closure correction of mercury injection capillary pressure measurements

Closure correction is a key requirement for a reliable petrophysical evaluation using mercury injection capillary pressure (MICP). The available correction methods rely on identifying deflection points on capillary pressure curves which is often difficult and subjective and requires additional information for macropores that control the closure effect. The proposed approach in this study is novel in terms of integrating the pore-throat size distribution and incremental mercury intrusion data from MICP with porosity from routine core analysis as well as 2D visualization and watershed segmentation from thin section images. The proposed approach allows for lowering the uncertainty in closure correction by incorporating the pore-throat sizes and segmented porosity of the macropores from thin-section images. We tested this approach on samples of the Austin Chalk and Indiana Limestone. The effects of sample size and equilibrium time were also investigated. Identifying the closure pressure is demonstrated to be more difficult on small crushed samples due to the impact of mercury conformance associated with the increased specific surface area. The impact of increasing the equilibrium time is insignificant on relatively permeable Austin Chalk. However, for the tighter Indiana Limestone, conducting fast MICP experiments results in inconsistent and misleading results. We used rate-equilibrium testing at 0.001 μL/g to generate initial-residual curves and evaluate pores accessibility. We show that Austin Chalk pores are fully intruded below 10,000 psia whereas Indiana Limestone requires higher pressure to invade all the pore systems. This study emphasizes the importance of integrating additional information with the MICP data for the closure correction of complex pore systems.

Pore Structure and Fractal Characteristics of Mixed Siliciclastic-Carbonate Rocks from the Yingxi Area, Southwest Qaidam Basin, China

Summary Evaluating reservoir properties at the pore scale is vital to better estimate hydrocarbon reserves and plan field development. The lacustrine mixed siliciclastic-carbonate deposits of the Upper Paleogene Xiaganchaigou Formation in the west Yingxiongling area form one of the most important hydrocarbon reservoirs in the southwestern Qaidam Basin (China). In this study, we analyzed well samples with X-ray diffraction (XRD), nuclear magnetic resonance (NMR), and mercury injection capillary pressure (MICP) data in integration with scanning electron microscopy (SEM) images to decipher the mineral composition and pore structure characteristics of the Xiaganchaigou Formation. We also calculate the fractal dimensions using MICP, NMR T2 spectrum, and SEM images based on fractal theory models. The results indicate that the mixed siliciclastic-carbonate samples of the upper section of the Xiaganchaigou Formation are mainly formed by dolomite and clay minerals with low siliceous and calcite content. Porosity is relatively low (2.01−9.83%) and positively correlated with dolomite content, thus indicating that the dolomite intercrystalline pores formed by infiltration and reflux dolomitization control the reservoir characteristics. The size of dolomite intercrystalline pores varies between several and hundreds of nanometers. The porosity has a poor correlation with permeability, which indicates that the pores are mostly primary, which lack the transformation of late dissolution. Three types of mixed siliciclastic-carbonate reservoirs are identified according to pore size distribution (<20 nm, 20−300 nm and multiple distribution), calculated using the NMR T2 spectrum. Fractal curves calculated by combining the MICP and NMR data are characterized by multisegments. The number of segments depends on the degree of heterogeneity of pore structure: two segment for high heterogeneity and three segment for low heterogeneity, also indicating a multifractal feature in mixed rock reservoirs. There is a negative correlation trend between porosity and fractal dimensions, and larger pores often have larger fractal dimensions. These results show that MICP-based fractal values are higher than those of NMR-based, which result from unconnected pores that the MICP is unable to reach. Fractal dimensions obtained from SEM have a small and narrow distribution range and are negatively correlated with the number of pores with smaller sizes. In essence, this study shows that the fractal dimension can be a concise index to evaluate the heterogeneity of lacustrine mixed siliciclastic-carbonate reservoirs, which can serve as an important reference for hydrocarbon development plans.

Understanding pore characteristics through core-based petrographic and petrophysical analysis in a heterogeneous carbonate reservoir: A case study from the Mumbai Offshore Basin, India

Carbonate rocks exhibit complex and heterogeneous pore structures; such heterogeneity is manifested by the occurrence of a wide variety of pore types with different sizes and geometries as a result of depositional and diagenetic processes. These complications substantially increase the uncertainty of predicted rock hydraulic parameters because samples with comparable porosities might have very different permeability values. In this study, small-scale characterisation of porosity and permeability in heterogeneous Eocene limestone samples from the Bassein Formation of the B-X structure of the MK Field in Mumbai Offshore Basin, India, was carried out, employing an integrated framework that incorporates thin-section petrography, routine core analysis, mercury injection capillary pressure and nuclear magnetic resonance data. The pore characteristics of these carbonates range from poor to excellent. The studied samples exhibited large ranges of porosity, permeability and other associated petrophysical attributes. The pore types, as well as their orientations and connectivity, are the primary factors causing the heterogeneity. Because of the complexity of the pore networks, a simple lithofacies classification alone would have been insufficient to link porosity and permeability. The reservoir characteristics in the study area are strongly linked to the development and/or destruction of reservoir porosity–permeability during different phases of diagenesis. Twenty-four carbonate core samples from the limestone unit were studied and classified into microfacies and pore type classes, producing an accurate assessment of reservoir attributes. The comprehensive workflow incorporates the pore volume distributions and pore throat attributes for each rock type. Three carbonate microfacies were identified by petrographic analysis and their petrophysical characteristics, such as porosity, permeability, pore throat size, pore volume and fluid flow factors, were measured. The study demonstrates how macroporosity, mesoporosity and microporosity are associated with various rock types and how they affect permeability and cementation exponents. The results of this study provide a comprehensive experimental framework for geological and geophysical interpretation that can be applied to identify potential reservoir facies and strengthen our understanding of heterogeneous carbonates. The framework can also be used to guide reservoir evaluation of similar heterogeneous formations in other areas.

Effects of pore size and pore connectivity on trapped gas saturation

Abstract Trapped or residual air (or gas) is known to affect the multiphase hydraulic properties of both soils and rocks. Trapped air is known to impact many vadose zone hydrologic applications such as infiltration and flow in the capillary fringe, but is also a major issue affecting recoverable oil reserves. Although many studies have focused on the relationship between porosity and trapped gas saturation (S gt ) in sandstones, far fewer studies have been carried out for carbonate rocks. This work aims to analyze the influence of porous media properties on trapped gas saturation in carbonate rocks. For this we used thirteen Indiana Limestone and Silurian dolomite rock samples from the USA, and several coquinas from the Morro do Chaves formation in Brazil. Pore size distributions were obtained for all samples using Nuclear Magnetic Resonance (NMR), and Mercury Injection Capillary Pressure (MICP) data from three of the samples to determine their pore throat size distributions. Additionally, 3D microtomography (microCT) images were used to quantify macropore profiles and pore connectivities. Results indicate a lower capacity of gas trapping in carbonate rocks in which micro- and mesopores predominate. Results also indicate that in carbonate rocks, pore size exerts a greater influence on the ability of gas trapping compared to pore connectivity, so that rocks with a predominance of macropores have greater capacity for gas trapping, even when the macropores are well interconnected. These findings show that pore characteristics very much affect the processes governing gas trapping in carbonate rocks, and indirectly the multiphase hydraulic properties and recoverable oil reserves of carbonate rock reservoirs.

Estimating the Permeability of Rocks by Principal Component Regressions of NMR and MICP Data

The estimation of continuous downhole permeability is widely performed by nuclear magnetic resonance (NMR) using the classical Seevers-Kenyon and Timur-Coates models. The first approach uses an average of the relaxation times, whereas the latter approach is based on the fractional fluid content computed from a relaxation time distribution cutoff. However, several case studies in the literature reported that these models might fail, especially when applied to complex carbonate rocks in which permeability is often less correlated to porosity, irreducible water saturation, and relaxation times. This study develops and evaluates perm-estimators that use multiple relaxation times, proving that they are a general case of the classical models. The so-called multivariate estimators are calibrated with core permeability using principal component regression, which describes NMR variables in a simple and linear-independent space according to data variance. An important feature of the multivariate approach is the possibility of simultaneously using longitudinal T1 and transverse T2 relaxation times or simply using a specific segment of their distribution. Moreover, the multivariate estimators can also be applied to size-scaled T1,2 distributions for cases in which relaxation times are less sensitive to permeability, such as the carbonate rocks studied in this work. By employing mercury injection capillary pressure (MICP) data for the NMR size scaling, permeability estimates are improved considerably compared to the nonscaled estimates. The superior results achieved with the novel multivariate estimators over the classical models indicate that core and NMR well-logging data should be better explored to improve the accuracy of permeability estimates.

Determination of pore size distribution in tight gas sandstones based on Bayesian regularization neural network with MICP, NMR and petrophysical logs

Mercury injection capillary pressure (MICP) is one of the most important means for quantitative study of pore structure, however, its application is often limited due to its expensive, destructive and dangerous characteristics. Nuclear magnetic resonance (NMR) then becomes a common alternative by log-linear conversion of transverse relaxation time (T2) spectrum into pseudo-MICP or pore size distribution (PSD) though the accuracy and generality is unconvincing. Petrophysical logs have rich geological-petrophysical information but are seldom used in pore structure research. In this paper, PSD determination of tight gas sandstones based on Bayesian regularization neural network (BRNN) with MICP, NMR and petrophysical logs is studied. A numerical workflow is developed to preprocess MICP and NMR experimental data and determine PSD. Subsequently, two BRNN models are constructed respectively with joint laboratory T2 spectrum and petrophysical logs as main inputs and pore radius and mercury saturation from MICP measurement as training target. It is revealed that, accurate PSD can be determined from prediction results of BRNN models, wherein the NMR-based BRNN can be employed to obtain PSD from more easily accessible NMR measurement and the log-based one is expected to be generalized in the field. Conversion of PSD by fitting pore radius with T2 through their piecewise linear or quintic polynomial relation in log-log coordinate is equivalent to underfitting or overfitting in accuracy of machine learning and is confined to laboratory NMR with joint MICP. Detailed discussion on BRNN modeling, pore radius fitting and the corresponding numerical workflow proposed here may provide valuable insight into petrophysical-log analysis and quantitative evaluation on pore structure of complex reservoirs.

Multimodal Carbonates: Distribution of Oil Saturation in the Microporous Regions of Arab Formations

Perhaps as much as 50% of the oil-in-place in carbonate formations around the world is locked away in the easy to bypass microporosity. If some of this oil is unlocked by the improved recovery processes focused on tight carbonate formations, the world may gain a major source of lower-rate power over several decades. Here, we overview the Arab D formation in the largest oil field on earth, the Ghawar. We investigate the occurrence of microporosity of different origins and sizes using scanning electron microscopy (SEM) and pore casting techniques. Then, we present a robust calculation of the probability of invasion and oil saturation distribution in the nested micropores using mercury injection capillary pressure data available in the literature. We show that large portions of the micropores in Arab D formation would have been bypassed during primary drainage unless the invading crude oil ganglia were sufficiently long. We also show that, under prevailing conditions of primary drainage of the strongly water-wet Arab formations in the Ghawar, the microporosity there was invaded and the porosity-weighted initial oil saturations of 60–85% are expected. Considering the asphaltenic nature of crude oil in the Ghawar, we expect the invaded portions of the pores to turn mixed-wet, thus becoming inaccessible to waterflooding until further measures are taken to modify the system’s surface chemistry and/or create substantial local pore pressure gradients.

A comparative study of permeability prediction for Eocene sandstones — Part 1: Application of modified Swanson models to mercury injection capillary pressure and nuclear magnetic resonance data

The mercury injection capillary pressure (MICP) method and nuclear magnetic resonance (NMR) relaxometry provide insight into the pore radius distribution (PRD) either of pore throats (MICP) or pore bodies (NMR) of rocks. One variety of permeability ( k) prediction models is based on the knowledge of the PRD. We have evaluated the quality of k-prediction models using a sample set of Eocene sandstones with known values of measured permeability. The Swanson method relates the apex point of the capillary pressure curve to k. Although this widely acknowledged method uses only a single point of the PRD, it provides a predictive quality with an average ratio between the measured and predicted permeability lower than a factor of three. The pore throat radius of the apex point proves to be a good proxy of the effective hydraulic radius. We determine that an improved k prediction can be achieved if a larger section of the PRD is considered in our generalized model. Using reliable values of surface relaxivity, the NMR relaxation time distribution is transformed into a PRD. We find that a characteristic apex point can be determined from NMR data, too. This characteristic point enables a good k prediction for the set of Eocene sandstone samples. In contrast to MICP, the predictive quality cannot be improved by applying an integration over a larger section of the PRD. Further tests with samples of different pore structure and lithology should demonstrate the potential of our models.

Applying NMR T2 Spectral Parameters in Pore Structure Evaluation—An Example from an Eocene Low-Permeability Sandstone Reservoir

The Eocene low-permeability sandstone reservoirs in the Dongying Depression, Bohai Bay Basin, China host a significant amount of oil reserves. The development of the reservoirs has been hampered by our inability to understand the complex and heterogeneous pore structures of the reservoirs. In this study, the pore systems, pore sizes, pore connectivity, and movable fluid distribution of the Eocene Shahejie Formation (Es4) sandstone reservoirs were investigated using an integrated analysis of optical and scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR). The full-range pore structures of the Es4 sandstone reservoirs were evaluated by using NMR experiments. Various NMR T2 spectral parameters suitable for describing the pore structures and movable fluid distribution were extracted through morphological and statistical analysis of NMR T2 spectra. In combination with corresponding MICP data and petrophysical properties, we have demonstrated the reliability and robustness of the T2 spectral parameters for pore structure characterization. Four types of pore structures (I, II, III, and IV) were distinguished from the NMR T2 spectral parameters in association with other petrophysical properties and macroscopic behaviors. We have demonstrated the effectiveness of using the NMR T2 spectral parameters to characterize and classify micropore structures, which may be applied to effectively evaluate and predict low-permeability reservoir quality.

Microporosity quantification using confocal microscopy

ABSTRACTIn carbonate rocks, pore diameters range in size over at least nine orders of magnitude, from submicrometer-scale voids to km-scale caves. This study is focused on micropores, which are defined as pore bodies with diameter ≤ 10 micrometers. Corresponding pore throats are generally ≤ 1 micrometer in diameter. To visualize and quantify microporosity, geologists commonly use pore casts, transmitted-light petrography, and scanning electron microscopy. Shortfalls exist in all of these techniques. Laser scanning confocal microscopy, a relatively new approach, provides a step change in our ability to image and quantify microporosity in carbonate rocks.Laser scanning confocal microscopy provides high-resolution (0.2-micrometers/pixel) images of micropores. Such pores are generally obscure or invisible using conventional petrography. In practice, confocal microscopy is applied to polished rock chips or thin sections that have been vacuum-pressure impregnated with epoxy. The laser light source interacts with fluorescent dye within the epoxy. Emitted fluorescent light, recorded using point-by-point illumination, indicates the physical location of pores. A pinhole, placed in front of the detector, eliminates out-of-focus light. Because each measurement is a single point, confocal microscopes scan along grids of parallel lines to provide optical images of planes at specified depths within the sample.Confocal microscopy is used to generate 2D and 3D images of pore bodies and throats. Results can be compared to laboratory-measured petrophysical properties, such as pore-throat diameters from mercury injection capillary pressure (MICP) data. Now, for the first time, we can compute pore-body to pore-throat size ratios without pore casts. These ratios are important, because they can be related to mercury recovery factors from imbibition MICP experiments.

Pore Structure and Seal Capacity of Ilaro Formation Shales in the Eastern Dahomey Basin: Implications from Mercury Injection Capillary Pressure and Spontaneous Imbibition Analyses

A petrophysical evaluation of caprock pore characteristics and seal capacity is critical for geologic storage of CO2. In this study, integration of X-ray diffraction, mercury injection capillary pressure (MICP), and spontaneous imbibition analyses is used to evaluate the pore characteristics and seal capacity of shale samples from the Ilaro formation, which could serve as a seal for CO2 injected into the reservoir units of the eastern Dahomey basin. X-ray diffraction reveals the samples as clay-rich and early diagenetic, while spontaneous imbibition reveals pore connectivity heterogeneity. MICP analysis shows the samples as being characterized by a low breakthrough pressure and reveals the mesopore dominance with majority of pore volumes dominated by 5 to 10 nm-sized pore throats. Furthermore, high CO2 column heights are obtained from conversion of MICP data (at 20% saturation) for mesopore-dominated samples containing ankerite and kaolinite. The study reveals that should injected CO2 migrate upward from the reservoir units of the onshore eastern Dahomey basin, portions of the Ilaro formation may function as a good seal due to the mesopore mineralogical composition influence on the CO2–brine–rock interaction. This result should therefore serve as an important insight for future caprock sealing studies conducted on the onshore eastern Dahomey basin.

Pore Structure Characterization of Eocene Low-Permeability Sandstones via Fractal Analysis and Machine Learning: An Example from the Dongying Depression, Bohai Bay Basin, China.

Poroperm analysis, mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) measurements were performed to delineate the pore structures and fractal behaviors of the Eocene low-permeability sandstones in the Dongying Depression, Bohai Bay Basin, China. Three types of pore structures (I, II, and III) have been classified by applying the self-organizing map (SOM) clustering model. Comparative analysis of three different fractal models indicates that the MICP tubular model and NMR model are quite effective for pore structure characterization. The results show that the reservoirs generally exhibit high fractal dimensions, indicative of complex pore structures. The presence of small pore throats is primarily responsible for the heterogeneities and complexities in the Eocene low-permeability sandstones. A modified Winland model was established for the permeability estimation using MICP data. Different from high-permeability reservoirs or unconventional (e.g., shale and tight formation) reservoirs, r10 is the best parameter for permeability estimation, indicating that the permeability of the Eocene low-permeability sandstones is largely controlled by the large pore systems. Additionally, a porosity model derived from movable fluids using NMR data has been established and provided better prediction effect compared with the classic Coates and Schlumberger Doll Research (SDR) models. Fractal analysis and permeability estimation are shown to be quite effective for investigating microscopic behaviors and in predicting the reservoir quality of low-permeability sandstone reservoirs.

Free or Bound? Thomeer and NMR Porosity Partitioning in Carbonate Reservoirs, Alta Discovery, Southwestern Barents Sea

The main etrophysical challenges in carbonate reservoirs are often to define meaningful rock types, then to establish robust permeability and saturation models for these rock types, as well as to develop a realistic estimation of irreducible water saturation (Swirr). Realistic Swirr estimation is important for predicting production behavior (expected development of water cut) and thus ultimately for planning the future development scheme of a discovery. In this study, we present the 2014 Alta discovery, located in the southwestern Barents Sea. More than 50% of the expected hydrocarbon resources reside within complex carbonate reservoirs of Permo-Carboniferous age that display highly variable rock properties. The initial screening revealed that primary rock textures and pore geometries were, for a large part, overprinted by diagenetic processes. Hence, better control on the reservoir’s diagenetic evolution will be needed to apply a full-scale rock typing workflow. In the meantime, it was decided to proceed with a simplified reservoir characterization approach based on the main stratigraphic building blocks. Sufficient core coverage allowed for using permeability measurements on core samples as direct input to a 3D reservoir model. A customized core analysis program, using whole-core samples, was designed to characterize the effect of large-scale vuggy pores. For modeling water saturation, a workflow based on the Thomeer hyperbola was developed that describes mercury injection capillary pressure (MICP) curves. The results adequately specify the saturation in all the stratigraphic building blocks. However, saturation uncertainty in the reservoir is high due to a highly variable cementation factor (m), unknown wettability, and the presence of residual oil below the current free-water level (FWL). The Alta structure has been and still is leaking gas, causing the FWL to rise over time. To address the otherwise underestimated volumes in the transition zone above the current FWL, a deeper pseudo-FWL was created and used as input to the saturation height function. Despite log-based water saturation (Archie) and core measurements (Dean-Stark) indicating more than 80% water saturation for less permeable reservoir rocks within the oil leg, production tests did not produce water at normal rates. This clearly demonstrated the need to distinguish “nonproductive” pore systems (with capillary-bound fluids; in this case, water) from pore systems contributing to production (“free” fluids). A large MICP data set confirmed that most reservoir rocks exhibit a mix of different pore types and pore-throat diameters. To model this accurately, porosity partitioning in nonproductive microporosity and movable porosity using the NMR logs was performed. Calibrating appropriate T2 cutoffs by matching core MICP to NMR logs in these heterogeneous rocks is seriously hampered by the large difference in sample size. Applying both MICP and NMR measurements to a subset of core plugs helped to resolve this challenge. Comparing the corresponding movable (“free”) porosity to total porosity revealed near-linear relationships for different reservoir rocks. For irreducible water saturation (Swirr), Swimmobile is calculated using the NMR-based movable porosity. Swimmobile is considered to be a close approximation of Swirr. The resulting full-field simulation showed a significantly improved match between model output and recorded well test data.

Micro/Nanopore Systems in Lacustrine Tight Oil Reservoirs, China.

A nanoscale pore throat system develops extensively in rocks of unconventional reservoirs serving as both source and reservoir rock. The nanoscale pores provide the main storage spaces, accounting for 70% to 80% of the total unconventional tight reservoirs in China. As one of most important unconventional petroleum accumulations, tight oil has accumulated in more than 20 lacustrine strata since the Permian in China. Three types of tight oil reservoirs were identified based on the lithology and provenance in the lacustrine basins, including terrigenous sandstone, endogenous carbonate rocks and mixed sedimentary rocks. The micro/nanopore structures of these tight rocks were investigated with the application of optical microscopy, scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), gas adsorption (GA) and nuclear magnetic resonance (NMR). The results indicated that the pore systems were connected by nanoscale throats dominated the storage spaces of the lacustrine tight oil reservoirs, while there were obvious differences among these three tight rocks, including pore types, pore size and movable fluid distribution. (i) The terrigenous sandstones, which were represented by the Triassic Chang 7 tight sandstones in the Ordos Basin and Cretaceous Quantou tight sandstones in the Songliao Basin, were mainly arkoses, and their storage space was mainly composed of dissolution pores and intraclay mineral pores. Feldspar, rock fragments and carbonate cements were the majority of the dissolved components, and the diameter of dissolution pores ranged from 1 micron to 50 microns. Abundant intrakaolinite and illite/smectite mixed layers pores were developed, and the pore size was 10 nm to 500 nm. The MICP and GA data suggested that storage spaces were connected by throats with diameters of 10 nm˜300 nm. (ii) The endogenous carbonate rocks, which were represented by the Jurassic Da'anzhai limestones in the Sichuan Basin, were the tightest rocks with porosities of less than 5% and permeabilities of less than 0.01×10-3 μm². The calcite dissolution pores and fractures with diameters of 10 nm˜500 nm were the most important storage spaces. The majority of pore systems were connected by throats with diameters of 6 nm˜100 nm based on the MICP and GA data. (iii) The tight mixed sedimentary rocks, which were represented by the Permian Lucaogou Formation in the Junggar Basin, were complex in lithologic composition, and dolostones and dolomite sandstones were the most important exploration targets. The interdolomite pores were the dominant storage spaces, in which abundant illite/smectite mixed layers were filled, and the pore size ranged from 50 nm to 50 microns. The MICP and GA data showed that the storage space was dominated by throats with diameters of 10 nm˜200 nm, and their volumetric contributions could reach over 70%. These results could provide a reference for future tight oil research and exploration in China.

QEMSCAN-Assisted Interpretation of Imbibition Capillary Pressure for Multiporosity Carbonate Rocks

Summary In this paper, we present an experimental study that explores the potential links between the imbibition capillary pressure Pci and the pore systems and/or mineralogy for carbonate reservoirs undergoing waterflood. A systematic workflow has been formulated to ensure the data quality of Pci, minimize uncertainty in deriving Pci from centrifuge tests, and analyze the data considering the pore-size distribution from mercury injection capillary pressure (MICP) and mineralogy from Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN). The workflow starts with assessing the centrifuge production data for gravity-capillary equilibrium at each speed. Then, the quality-checked data are used to generate six different Pci curves using analytical and numerical models. The resulting curves provide a measure of the variability in solutions for various rock types and assist in the selection of the most-representative Pci curve. Finally, the representative Pci curves of all rock samples are analyzed together with the MICP and QEMSCAN data to examine the change in Pci curves as a result of changes in the number and character of rock types, pore systems, dominant pore-throat radii, and mineralogy. Findings from this study shed light on the impact of mineralogy and pore systems on Pci. From the mineralogy perspective, the presence of dolomite, microporous calcite, or rutile and anatase (TiO2) within the rock composition is found to affect the Pci of the carbonate samples used in this study. The rock samples with these minerals should be separated from other bimodal samples before attempting to obtain a correlation between Pci and pore systems. The data analysis further reveals that some bimodal samples of medium permeability yield a better waterflood imbibition efficiency than those of the high-permeability samples. This observation is attributed to a better communication between the micropore and macropore systems, and a closer proximity of the peak radii of the micro- and macropore systems of the medium-permeability samples.

A new model to estimate permeability using mercury injection capillary pressure data: Application to carbonate and shale samples

Estimating permeability of carbonate rocks using mercury injection capillary pressure (MICP) data has been carried out by many researchers in the past few decades. However, a major issue with almost all of the existing models is that they focus on a single aperture value from the capillary pressure curve. This study builds a new model to extract permeability from the entire pore throat sizes. Fermic-Dirac function was applied to fit the MICP curve to obtain some critical parameters such as R1 (the large curvature value) and R2 (the small curvature value). Afterwards, the partial least squares regression method was employed to develop a new permeability model. To verify the new model and check other models, we studied ten carbonate rock samples from an Iranian oil reservoir. The results showed that the R1 values vary from 1.00 to 2.73 while R2 values are found between 0.23 and 1.00. The new model performed better than the published models. The idea of building the model for the carbonates can be used in developing the permeability estimating model for shale samples, which could be a new model for the shale permeability estimation.