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Abstract Core analysis techniques have traditionally been used mainly for hydrocarbon reservoir applications. However, the same techniques are equally applicable to reservoir issues associated with energy transition, such as geothermal prospects, carbon geosequestration, and hydrogen storage. Traditionally, much core analysis has been performed successfully using core plugs. However, this approach has certain drawbacks: (1) the selected plugs may not necessarily be representative of the full range of lithologies, (2) key features (e.g., thin naturally cemented or fractured zones) may be missed, (3) high-resolution detail at the lamina scale may be missed, (4) depth shifting to well logs may not be sufficiently accurate, and (5) this strategy may be more sensitive to missing core. In this paper, we highlight the usefulness of probe core analysis techniques on slabbed core and powdered samples. For many reservoirs relevant to energy transition, it is crucial to have a high-resolution continuous record of petrophysical properties so that key features are not missed. Probe measurements are less destructive, without the need to cut core plugs, and provide: (1) high-resolution data at the lamina scale so that key features and small-scale heterogeneities can be identified, (2) improved depth matching to well-log data, and (3) rapid, cost-effective data. We describe examples highlighting some different probe techniques. While some techniques are well known, such as probe permeability, others, such as probe acoustics, probe luminance (from linear X-ray measurements), and probe magnetics, are less familiar to core analysts but are well suited for analyzing cores from reservoirs associated with energy transition as well as hydrocarbons. For example, potential geothermal prospects involve studying igneous and metamorphic samples (where the main radiogenic heat sources reside) as well as sedimentary samples, and differences in the magnetic susceptibility signals using a small, portable magnetic probe can quickly differentiate the different rock types. Probe acoustics can be used to (1) rapidly identify anisotropy by orienting the acoustic transmitter-receiver bracket in different directions, (2) identify open microfractures via longer transit times, and (3) produce high-resolution porosity profiles after correlation of transit times with some representative plug or well-log porosity data. Probe luminance and associated linear X-ray images, which are related to density, can indicate small-scale heterogeneities that may impact permeability variation and anisotropy and may not be seen from mere visual observations of the slabbed core surface.
- North America > United States (1.00)
- North America > Canada > Alberta (0.69)
- Europe > Norway (0.68)
- Asia > Middle East (0.68)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geophysics > Magnetic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Rannoch Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > NOAKA Project > Krafla North Prospect > Etive Formation (0.98)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Flow-Dependent Relative Permeability Scaling for Steady-State Two-Phase Flow in Porous Media: Laboratory Validation on a Microfluidic Network
Karadimitriou, Nikolaos (University of Stuttgart) | Valavanides, Marios S. (University of West Africa) | Mouravas, Konstantinos (University of West Africa) | Steeb, Holger (University of Stuttgart)
Abstract Conventionally, the relative permeabilities of two immiscible fluid phases flowing in porous media are considered and expressed as functions of saturation. Yet, this has been put into challenge by theoretical, numerical, and laboratory studies of flow in artificial pore network models and real porous media. These works have revealed a significant dependency of the relative permeabilities on the flow rates, especially when the flow regime is capillary to capillary-viscous dominated, and part of the disconnected nonwetting phase remains mobile. These studies suggest that relative permeability models should include the functional dependence on flow intensities. However, revealing the explicit form of such dependence remains a persistent problem. Just recently, a general form of dependence was inferred based on extensive simulations with the DeProF model for steady-state two-phase flows in pore networks. The simulations revealed a systematic dependence of the relative permeabilities on the local flow rate intensities. This dependence can be described analytically by a universal scaling functional form of the actual independent variables of the process, namely, the capillary number, Ca, and the flow rate ratio, r. The proposed scaling incorporated a kernel function, the intrinsic dynamic capillary pressure (IDCP) function, describing the transition between capillarity- and viscosity-dominated flow phenomena. In a parallel laboratory study, SCAL measurements provided a preliminary proof-of-concept on the applicability of the model. In the laboratory study presented here, we examine the applicability of the scaling model by taking extensive, ex-core measurements of relative permeabilities for steady-state co-injections of two immiscible fluids within an artificial microfluidic pore network, across different flow regimes in Ca and r. From these measurements, we calculate the values of the mobility ratio, and we compare these to the corresponding values of the flow rate ratio. We also extract the IDCP curve, the locus of critical flow conditions, whereby the process is more efficient in terms of energy utilization – accounted by the nonwetting phase flow rate per unit of total power provided to the process, as well as the locus of flow conditions of equal relative permeabilities. We show that the degree of consistency between flow rate ratio and mobility ratio values, the IDCP curve, the locus of critical flow conditions, and the locus of equal relative permeabilities, as well as some associated invariant characteristic values, can be used for assessing the extent of end effects and for characterizing the flow as capillary- or viscous-dominated. The proposed scaling introduces new opportunities for enhancing SCAL protocols and their associated applications. These include the characterization of systems and flow conditions, dynamic rock typing, evaluation of capillary end effects, as well as the advancement of more efficient field-scale simulators. Additionally, it paves the way in designing more energy-efficient EOR interventions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Information Technology > Communications > Networks (0.66)
- Information Technology > Artificial Intelligence (0.48)
Joint Inversion of Saturation and Qv in Low-Permeability Sandstones Using Spontaneous Potential and Resistivity Logs
Zhao, Peiqiang (China University of Petroleum (Beijing)) | Wang, Yuetian (China University of Petroleum (Beijing)) | Li, Gaoren (PetroChina) | Hu, Cong (PetroChina) | Xie, Jiarui (China University of Petroleum (Beijing)) | Duan, Wei (China University of Petroleum (Beijing)) | Mao, Zhiqiang (China University of Petroleum (Beijing))
Abstract Hydrocarbon saturation is an important formation parameter and the basis for quantitative reservoir evaluation. However, the saturation models of shaly sandstones contain more parameters than clean sandstones; therefore, determining these parameters for shaly sandstone is difficult. In this study, based on the response of spontaneous potential (SP) logging, the membrane potential equations of shaly sandstone in water-saturated and oil-water states were derived, and an analytical equation of the anomaly amplitude of the SP in shaly sandstone was obtained. On this basis, the influencing factors of the SP anomaly were analyzed. Furthermore, a joint inversion of SP and resistivity was established to calculate oil saturation and cation exchange capacity per unit pore volume (Qv). The SP log was interpreted using the proposed analytical model, and the resistivity log was processed using the Waxman-Smits model. The particle swarm optimization method was used to resolve the objective function. Finally, the method was applied to the Chang 8 Reservoir in Yanchang, on the western edge of the Ordos Basin, China. The resistivity and SP log curves synthesized using the inverse parameters agree with the field logs. The inversion of the saturation and Qv is consistent with core data and oil testing, indicating that the joint inversion method is stable, reliable, and accurate.
- Asia > China > Shaanxi Province (0.49)
- Asia > China > Shanxi Province (0.35)
- Asia > China > Gansu Province (0.35)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Ningxia > Ordos Basin > Changqing Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects
Laronga, Robert (SLB) | Borchardt, Erik (SLB) | Hill, Barbara (SLB) | Velez, Edgar (SLB) | Klemin, Denis (SLB) | Haddad, Sammy (SLB) | Haddad, Elia (SLB) | Chadwick, Casey (SLB) | Mahmoodaghdam, Elham (SLB) | Hamichi, Farid (SLB)
Abstract Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as - Storage capacity - Injectivity - Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- North America > United States > New Mexico (0.67)
- Europe > Norway (0.67)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (32 more...)
Abstract Relative permeability and capillary pressure are important parameters in reservoir simulations because it helps in understanding and anticipating oil and/or gas production scenarios over the years. They are both obtained in a laboratory after establishing the required initial conditions. As a matter of fact, before measuring imbibition relative permeability and capillary pressure, it is recommended to set initial rock reservoir conditions by establishing appropriate initial water saturation (Swi) and by aging the core to restore the reservoir wettability. There are several conventional techniques to establish Swi. Viscous flooding is a fast technique, but it may create a non-uniform saturation profile and, in some cases, be inefficient in reaching low Swi targets. Centrifugation is a capillary-driven technique that is also very fast; however, the possibility of not desaturating the outlet face is a significant constraint. In both cases, reversing flow direction is generally performed to flatten the saturation profile; however, this phenomenon is poorly controlled. The application of capillary pressure by porous plate allows targeting a specific value of Swi and generates a uniform saturation profile; however, it is a very time-consuming method. In this paper, we present the Hybrid Drainage Technique (HDT), which couples viscous flooding and porous plate approaches, significantly reducing the experimental duration when setting Swi. Another advantage of the method is the possibility of setting a uniform saturation profile at the targeted Swi. A specific core holder, adapted to nuclear magnetic resonance (NMR) imaging and capable of performing both viscous flooding and porous plate testing without unloading the rock, was designed. Using this core holder enables performing aging and imbibition coreflood testing with no further manipulation of the core sample. Monitoring saturation profiles was made possible by using an NMR imaging setup. The method has been tested and validated on two outcrop samples from Bentheimer (sandstone) and Richemont (limestone), drastically reducing the experimental time of the primary drainage step in comparison to classical porous plate drainage but also leading to uniform water saturation profiles. The experiment duration is reduced, and it enables the realization of coreflooding; therefore, this technique may be used for larger samples classically used in relative permeability experiments. This approach is preferred as it provides faster and more reliable measurements of saturation.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract Complex lithology petrophysical interpretation with multiphysics logging tools has been and continues to be a major challenge in formation evaluation. Many currently used data-driven approaches, such as a neural network (NN), deliver predicted results in numerical quantities rather than analytical equations. It is more challenging if multiphysics logging measurements are collectively used to estimate a petrophysical parameter. To overcome these problems, a physics-guided, artificial intelligence (AI) machine-learning (ML) method for petrophysical interpretation model development is described. The workflow consists of the following five constituents: (1) statistical tools such as correlation heatmaps are employed to select the best candidate input variables for the target petrophysical equations; (2) a genetic programming-based symbolic regression approach is used to fuse multiphysics measurements data for training the petrophysical prediction equations; (3) an optional ensemble modeling procedure is applied for maximally utilizing all available training data by integrating multiple instances of prediction equations objectively, which is especially useful for a small training data set; (4) a means of obtaining conditional branching in prediction equations is enabled in symbolic regression to handle certain formation heterogeneity; and (5) a model discrimination framework is introduced to finalize the model selection based on mathematical complexity, physics complexity, and model performance. The efficacy of the five-constituents petrophysical interpretation development process is demonstrated on a data set collected from six wells with the goal of obtaining formation resistivity factor (F) and permeability (k) equations for heterogeneous carbonate reservoirs. We show quantitatively how individual constituents of the workflow improve the model performance with two error metrics. A comparison of NN-method-predicted permeability values vs. SR-based-workflow-predicted permeability equation is included to showcase many advantages of the latter. Beyond the transparency of an analytical form of the prediction equations, the SR method intrinsically has a more relaxed requirement on the training data size, is less prone to overfitting, yet can deliver superior model performance rival to the NN approach.
- North America > United States > Texas > Permian Basin > Midland Basin > Kingdom Field > Abo Reef Formation (0.98)
- North America > United States > Texas > Permian Basin > Midland Basin > Kingdom Field > Abo Formation (0.98)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract Due to the complexity of lithologies and pore types, the permeability calculation of complex carbonate reservoirs has always been a difficult problem. To accurately calculate the permeability of complex carbonate reservoirs, a data mining technique is introduced. The technical process of data mining is established and divided into seven steps: data warehousing, data preprocessing, classification of reservoir types, selection of sensitive parameters, establishment of the classification model, evaluation of classification model, and application of classification model. The data-driven method can find effective knowledge that conventional reservoir evaluation methods cannot recognize and that are still contained in oil and gas data. Since the data-driven method may acquire a large amount of invalid knowledge while obtaining effective knowledge, the domain knowledge needs to be introduced to participate in the data mining process. The domain-knowledge-driven method can extract the most valuable and effective information from oil and gas data. The combination of data-driven and domain knowledge-driven methods is possible to avoid subdividing lithologies and pore types of complex carbonate reservoirs. As a result, the permeability of complex carbonate reservoirs can be accurately calculated based on the combination of data-driven and domain-knowledge-driven methods. Compared with the permeability calculation result by the previous method, the accuracy of the permeability calculation result by the data mining technique is improved by 18.39%. The combination of data-driven and domain-knowledge- driven methods can solve the difficult problem that traditional reservoir evaluation methods cannot overcome. Additionally, they can also provide new theories and techniques for reservoir evaluation. The permeability calculation result proves the feasibility and correctness of the method.
- Asia > China (0.29)
- Asia > Middle East (0.28)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract In carbonate reservoirs, permeability prediction is often difficult due to the influence of various geological variables that control fluid flow. Many attempts have been made to estimate permeability from porosity by using theoretical and empirical equations. The suggested permeability models have been questionable in carbonates due to inherent heterogeneity and complex pore systems. The main objective of this paper is to provide a workflow to improve the use of existing models (e.g., Kozeny, Lucia, and Winland) to predict permeability in carbonate reservoirs. More than 1,000 core plugs were studied from seven different carbonate reservoirs across the Middle East: mainly Cretaceous reservoirs. The plugs were carefully selected to represent a wide range of properties within the cored intervals. The data set available included laboratory-measured helium porosity, gas permeability, thin-section photomicrographs, and high-pressure mercury injection. Rock textures were analyzed in the thin-section photomicrographs and were classified based on their content as grainy, muddy, and mixed. Special attention was given to the diagenesis effects, mainly compaction, cementation, and dissolution. The texture information was plotted in the porosity-permeability domain and was found to produce three distinct porosity-permeability relationships. Each texture gave a unique porosity-permeability trend, where the extent of the trend was controlled by diagenesis. Rock types were defined on each trend by detailed texture analysis and capillary pressure. Three different permeability equations (Kozeny, Winland, and Lucia) were evaluated to study their effectiveness in complex carbonate reservoirs. Both Kozeny and Lucia models honored the geology of the samples and showed similar trends to the porosity-permeability relationships, whereas the Winland model gave different slopes to the experimental data. The prediction of the permeability was improved by using different model parameters per RRT within each texture. This work presents a systematic approach to construct correlations between porosity and permeability in complex carbonate reservoirs. Model parameters (i.e., FZI, RFN, and r35) were suggested within different geological rock types to estimate permeability. Based on the workflow presented in the paper, the predicted permeability was improved to less than a factor of 2 compared to the measured values. Moreover, the same workflow was applied using the data from seven different reservoirs, and the same rock typing scheme was applicable to all the reservoirs. Such work is not abundant in the literature and would serve to improve permeability prediction in heterogeneous carbonate reservoirs, which is one of the main uncertainties in modeling carbonates.
- Europe (1.00)
- Asia > Middle East > UAE (0.47)
- North America > United States > Texas (0.46)
Brooks and Corey (1964) and van Genuchten (1980) proposed the two most widely used relations for approximating capillary pressure. Petroleum engineers apply both, but they were originally proposed to understand the moisture content in soil whose void space differs from that of shale. This paper presents an empirical relation that can capture the nonplateau-like trend and the approximate capillary pressure in shale. It also implements the nonzero entry pressure, which the van Genuchten model cannot capture. This study compares the performance of the proposed model with those of Brooks and Corey and van Genuchten by determining the nonlinear regression coefficient (R) and the mean square error (MSE). It uses mercury capillary pressure data of US shales available in the literature. The data set comprises 30 samples collected from the Bakken, Eagle Ford, and Greenhorn Formations with average permeability of less than 1 md and average porosity of 5%. The proposed model has applications in characterizing two-phase displacement in shales.
- North America > United States > Colorado (1.00)
- North America > Canada (1.00)
- Asia > Middle East (1.00)
An Efficient Laboratory Method to Measure Stress-Dependent Tight Rock Permeability With the Steady-State Flow Method
Zhang, Jilin Jay (Aramco Services Company - Aramco Research Center-Houston) | Liu, Hui-Hai (Aramco Services Company - Aramco Research Center-Houston) | Duncan, Jewel (Aramco Services Company - Aramco Research Center-Houston)
The matrix permeability of tight formations is important for many geological and engineering applications, such as CO2 geological sequestration, disposal of nuclear waste, and production of unconventional hydrocarbon and coalbed methane. In the case of hydrocarbon production, the reservoir permeability decreases with decreasing pore pressure or increasing effective stress. Laboratory characterization of the relationship between matrix permeability and effective stress (and pore pressure) is generally time consuming since the current methods are based on the so-called point-by-point approach that measures one permeability data point only with one test run, and the relationship is generally represented with multiple data points. In this paper, we present a method to determine matrix permeability, its relationship with effective stress, and the Biot coefficient of a tight rock sample with three steady-state flow test runs using large pressure gradients. Unlike the traditional steady-state flow method based on linear flow theories, analytical results based on a nonlinear flow theory are used for determining the related relationship and parameters. The gas properties and permeability along the core sample vary with gas pressure and effective stress, while the traditional method treats them as constants for a given test run. To get the same set of parameters, our method only requires three test runs, and each test run of our method takes a much shorter time than the traditional method because our method is based on nonlinear flow theory and thus allows for the use of large pressure gradients. Comparisons of the permeability measurements with those obtained using traditional methods and numerical simulations demonstrate that our new method can get satisfactory results.
- Europe (0.88)
- North America > United States > Texas (0.46)
- North America > Canada > British Columbia (0.46)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)