Reservoir Petrophysical Properties Research Articles

Heterogeneous Reservoir Petrophysical Property and Controlling Factors in Semi-Restricted Depositional Setting: A Case Study of Yamama Formation, X Oilfield, Middle East

The Early Cretaceous Yamama Formation of X oilfield, deposited in a semi-restricted setting, holds considerable oil reserves. However, the reservoir is extremely heterogeneous and is poorly studied. Integrating outcrops, cores, cast thin sections, regular or special core analysis, wireline logging data from six wells, and seismic data, this study provides an improved understanding of reservoir petrophysical characteristics and geological controlling factors including sedimentation, diagenesis, and sequence. The results showed that eight lithologies are developed in the Yamama Formation, of which packstone and wackstone are dominant. The physical properties span a wide range, with porosity mainly distributed between 10% and 25%, and the permeability mainly distributed between 0.1 mD and 1 mD. Nine types of pores are developed, with moldic pores, micropores, and skeletal pores being the most developed. The reservoir has six types of microstructures, of which the poorly sorted with mega-throat represent the best reservoir. The Yamama Formation was mainly deposited in a lagoon, along with five other facies, such as supratidal flat, patchy reef, back shoal, shoal, and open shelf. Six types of diageneses are developed, with dissolution during the penecontemporaneous stage being the most beneficial to the reservoir and cementation being the most destructive. Three sequences were recognized in the Yamama Formation. It concluded that the hydrodynamics in semi-restricted depositional setting is weak overall and does not have the potential to develop large-scale high-quality reservoirs. A wide range of bioclasts were selectively dissolved to form a large number of secondary pores. Sediments rich in Algae, Bacinella, and peloids tend to form moldic pores, skeletal pores, and intergranular pores, respectively, which are prone to be favorable reservoirs. Controlled by the coupling of sedimentation and diagenesis driven by sequence, the reservoir is extremely heterogenous.

Assessing Cutoff Values and Evaluating Petrophysical Properties of a Shaly-Sand Reservoir with Heterogeneous Properties in a Southern Iraqi Oil Field

Assessing Cutoff Values and Evaluating Petrophysical Properties of a Shaly-Sand Reservoir with Heterogeneous Properties in a Southern Iraqi Oil Field

The Effect of Diagenetic Minerals on the Petrophysical Properties of Sandstone Reservoir: A Case Study of the Upper Shallow Marine Sandstones in the Central Bredasdorp Basin, Offshore South Africa

The upper shallow marine sandstone reservoirs of the Barremian-to-Valanginian formation are the most porous and permeable sandstone reservoirs in the Bredasdorp Basin and an important target for oil and gas exploration. There is a paucity of information on the reservoir characterization and effect of diagenetic mineral studies focusing on the upper shallow marine sandstone reservoirs in the central Bredasdorp Basin; thus, there is a need to investigate the effect of diagenetic minerals and to characterize these reservoirs due to their high porosity and permeability. Datasets, including a suite of geophysical wireline logs, routine core analysis, geological well completion reports, description reports, and core samples, were utilized. A total of 642 core porosity measures, core water saturation, and core permeability data were used for calibration with the log-derived parameters, ranging in depth from 3615 m to 4259 m. Rock samples were prepared for diagenetic mineral analyses, such as thin sections and Scanning electron microscopy, for each well to investigate the presence of diagenetic minerals in the selected reservoir units. The petrophysical analyses showed the results of porosity, volume of clay, water saturation, and permeability, ranging from 9% to 27%, 8.6% to 19.8%, 18.9% to 30.4%, and 0.096 mD to 151.8 mD, respectively, indicating a poor-to-good reservoir quality. Mineralogical analyses revealed that micrite calcite, quartz cement, quartz overgrowth, and authigenic pore-filling and grain-coating clay minerals (illite–smectite and illite) negatively affected intergranular porosity. Porosity-versus-permeability cross plot showed good correlation of 0.86 for ZN1 and 0.83 for ZN3 reservoirs, suggesting that although porosity is the main drive of permeability, there were other geological factors at play, such as diagenetic minerals and compaction.

Deep Sandstone Reservoir Characteristics and Pore Structure Classification Based on Fractal Theory: A Case Study of the Bayingobi Formation in Guaizihu Sag, Yin'e Basin.

The paper focuses on deep oil and gas resources in the Bayingobi Formation of Guaizihu Sag in the Yin'e Basin. Previous studies overlooked the differences between the pores and throats, mainly focusing on pore analysis. This work aims to analyze the pore structure and petrophysical properties of the reservoir using various methods. The study utilized the constant velocity mercury intrusion method to quantify pores and throats separately. Scanning electron microscopy and casting thin section techniques characterize the pore and throat morphology. The analysis compares the pore structures in reservoirs with different petrophysical properties. Additionally, pore and throat types are classified based on fractal dimensions, and factors influencing their development are discussed. Results reveal feldspar lithic sandstone as the predominant rock type with a low compositional maturity. The sandstone reservoirs exhibit low porosity (10.23%) and ultralow permeability (0.99 mD). Primary reservoir pore spaces include intergranular pores, dissolution pores, and microfractures. Pore radius averages at 195.32 μm, while throat radius is 3.76 μm. Pore structures are categorized as micropore small-throat, small-pore small-throat, and large-pore coarse-throat types. The study area generally exhibits a high pore-to-throat ratio, impacting reservoir petrophysical properties significantly. Pore development is primarily influenced by early diagenesis, organic acid dissolution, and hydrocarbon filling. Weak compaction and cementation transformations provide a material and spatial basis for the subsequent dissolution. The presence of thick organic-rich mudstone above and below the reservoir contributes to organic acid dissolution and hydrocarbon filling.

Petrophysical Property Prediction from Seismic Inversion Attributes Using Rock Physics and Machine Learning: Volve Field, North Sea

An accurate petrophysical model of the subsurface is essential for resource development and CO2 sequestration. We present a new workflow that provides a high-resolution estimate of petrophysical reservoir properties using seismic data with rock physics modeling and machine-learning techniques (i.e., deep learning neural networks). First, we compare the sequential prediction of the following petrophysical attributes: mineralogy, porosity, and fluid saturation, with the simultaneous prediction of all of the properties using the Volve field in the Norwegian North Sea as an example. The workflow shows that the sequential prediction produces a more efficient and accurate classification of petrophysical properties (the RMS error between the predicted and the original seismic trace is 50% smaller for the sequential compared to the simultaneous procedure). Next, the seismic amplitude response of the reservoirs was studied using rock physics modeling and amplitude versus offset (AVO) analysis to distinguish the different lithologies and fluid types. To ascertain the optimal hydrocarbon production areas, we performed Bayesian seismic inversion and applied machine learning to estimate the petrophysical properties. We examined how porosity, Vclay, and fluid variations affect the elastic properties. In Poisson’s ratio versus the P-wave impedance domain, a 10% porosity increase decreases the acoustic impedance (AI) by 30%, while a 20% Vclay decrease increases the AI by 12%. The Utsira Formation in the Volve field (5 km north of the Sleipner Øst field) was evaluated as a potential CO2 geological storage unit using Gassmann fluid substitution and seismic modeling. We look to assess the elastic property variation caused by CO2 saturation changes for monitoring purposes and simulate the effect. In the first 10% CO2 substitution, the P-wave velocity decrease is 12%, a subtle effect is observed for higher CO2 saturation values, and S-wave velocity (Vs) increases with CO2 saturation. Our analysis aspires to assist future reservoir studies and CO2 sequestration in similar fields.

Curved Pseudo Elastic Impedance based on Elastic Attribute Rotation Scheme for Reservoir Petrophysical Property Prediction

Seismic based reservoir characterization commonly attempts to estimate petrophysical properties of a reservoir from a combination of elastic attributes resulted from seismic inversion. Two most wanted main reservoir properties to be estimated are porosity variation and hydrocarbon saturation across the reservoir. A combination of acoustic impedance (AI) and the ratio between P- and S-wave velocities (Vp/Vs ratio) based on rock physics models had been used in the earlier study to form Curved Pseudo Elastic Impedance (CPEI) attribute. However, the approach involved a fourth order polynomial in the logarithmic domain of AI and Vp/Vs ratio. A much simpler approach of combining these elastic properties to form CPEI attributes which is based on attribute rotation scheme is proposed in this study. To illustrate the methodology, we applied to well and seismic data located in the Natuna Basin, Indonesia. Results show that better attributes correlation to porosity and hydrocarbon saturation variation is achieved.

Reservoir tortuosity prediction: Coupling stochastic generation of porous media and machine learning

Accurate reservoir tortuosity prediction is the foundation of the high-quality evaluation of reservoir petrophysical properties. However, conventional empirical equations as a form of experimental data fitting lacks universality because the data are usually from a single horizon or block. We developed a model combining the stochastic generation of porous media with machine learning (ML) to predict reservoir tortuosity based on pore structure parameters. Real core scanning images from public databases were employed in stochastic generation as reference, which is an economic and accurate method of meeting the dataset quality and scale requirements of ML. The particle swarm optimization algorithm, an efficient method of obtaining the best hyperparameter combination, was introduced for the hyperparameter tuning of six commonly used ML algorithms to determine the optional model for tortuosity prediction. Our trained ML models demonstrated superior tortuosity prediction accuracy over deterministic linear and exponential empirical equations with porosity as the only variable, which effectively demonstrates the potential of tortuosity prediction using pore structure parameters. The proposed ML model enables precise tortuosity predictions based on a few measurable pore structural features, which can be obtained from well logging data and CT scanning; thus, it can be widely used in petroleum and logging fields.

Mineralogical and Geochemical Study of the Asmari Group in the Fauqi Oil Field in Maysan, Southeastern Iraq

The presence of clay minerals of any kind and in any quantity and distribution pattern in hydrocarbon wells causes many problems in the qualitative assessment of the reservoir, A geochemical and mineralogical study are conducted on the reservoir units of the Asmari Group (early Miocene-Oligocene) to identify the clay mineral types present in the reservoir and the effect these clay minerals have on the reservoir's petrophysical properties. the Jeribe Formation (unit A) and the Upper Kirkuk Formation (unit B) are represented the main units of the Asmari reservoir ten samples from the Asmari group of the Fauqi oil field were chosen: five from the southern dome denoted by a number 65 and the same from the northern dome denoted by a number 64, Samples 1 and 2 represent unit A, while samples 3, 4, and 5 represent unit B. The mineralogical study showed that the non-clay minerals are represented by dolomite, calcite, anhydrite, quartz, and halite, while the clay minerals are represented by Illite, kaolinite, and chlorite, the geochemical analysis showed that the main oxides in the reservoir units of the Al-Asmari group are: silica, alumina, iron oxide, calcium oxide, magnesium oxide, sodium oxide, potassium oxide, titanium dioxide, sulfate, and chlorine, the highest percentage of the main oxides are calcium oxide, sulfate, and silica, respectively, and that the northern dome has a higher percentage of calcium, magnesium, sulfate, and the loss of ignition than the southern dome, while the percentage of silica and alumina in the southern dome is higher than its percentage in the northern dome which indicates a high percentage of clay minerals in the southern dome. The positive correlation between potassium and sodium and the negative correlation between potassium and calcium indicates that the Illite is of the Na-Illite type. Due to its lower charge Na and weak hydrogen bonds, Na-illite has greater dispersibility than Ca-illite and is present in all samples, making it the most clay mineral affecting the petrophysical properties in the study area.

Geostatistics Application in 3-D Reservoir Modeling for Calculation of Hydrocarbon Resources, Case Study: North Rembang Area

Oil and gas are still indispensable commodities to meet Indonesia's energy needs in the next few decades, even though government policies related to energy transition towards net zero emission have begun to be encouraged. However, the oil and gas requirement is not followed by the availability of reserves or resources owned by Indonesia. The objective of this study is to discover new hydrocarbon resources, through 3-D reservoir modeling using geostatistical method. The geostatistical method is still the best current method to predict the distribution of facies association and reservoir petrophysical properties such as porosity and water saturation. In facies association modeling, a stochastic geostatistical method is used, namely the Truncated Gaussian with Trends (TGS) algorithm. For porosity and water saturation (SW) modeling, the Sequential Gaussian Simulation (SGS) algorithm was applied. The results of 3-D modeling of facies associations, porosity, and water saturation are utilized to estimate gas resources in the North Rembang Area. From the estimation of gas resources, it is recognized that the Rembang Utra Area has accumulated gas resources around 3 TCF.

Injectivity assessment for CCS field-scale projects with considerations of salt deposition, mineral dissolution, fines migration, hydrate formation, and non-Darcy flow

This paper aims to review the main mechanisms identified in the lab scale that impact CO2 injectivity during CCS projects in saline aquifers and evaluate their relevance in field scale through numerical models. They may include water vaporization, salt precipitation in the dry-out zone, mineral dissolution, which can result in fines migration in porous media, CO2 hydrate formation, and effects of non-Darcy flow. All those mechanisms are observed from lab experiments and significantly impact reservoir petrophysical properties such as porosity and permeability and consequently on injectivity in field operations. This study includes these mechanisms in numerical models to quantify their impacts on the CO2 injectivity well index in synthetic and real field cases. In addition, a sensitivity analysis was performed for a range of brine compositions of seawater and higher salinities. This analysis shows an additional injectivity reduction as the salinity increases due to the halite scale, in agreement with the lab data from the literature. Another dependence evaluated in this study is when the ratio between capillary and viscous forces is decreased, reducing the injectivity. Additionally, when mineral reaction dissolution is considered in our modeling, it is possible to observe two occurring competitive phenomena, where the mineral dissolution can compensate for part of the injectivity loss due to salt deposition in the dry-out zone. That is especially relevant when the reservoir rock matrix is rich in reactive minerals, such as calcite and dolomite. However, mineral dissolution may lead to fines, and the risk of fines migration can lower the injectivity by at least 10% within five years of CO2 injection, according to our results. The mineral dissolution is also considered in these calculations, and the loss in injectivity is the net result of dissolution and fines migration. The gain in porosity–permeability as the results of mineral dissolution was modeled using the Kozeny-Carman equation. The results show the importance of considering the uncertainty of injectivity loss in CCS projects, where the amount of CO2 captured for storage must be injected often with no other alternatives, highlighting the need to provide flexibility in project planning to deal with such risks.

Hydrocarbon evaluation and distribution in Well-X and Well-Y in the Niger Delta Basin: Findings and validation through porosity comparison

The aim of this study is to integrate well logs and core data to identify reservoir characteristics and determine the reservoir's petrophysical properties in order to improve the understanding of the reservoir and provide valuable information for reservoir management. Wells X and Y of the ‘SCOJAS’ Field in the Niger Delta Basin of Nigeria were analyzed using Gamma ray logs, Resistivity logs, Sonic, Neutron and Density Logs. The obtained results were compared with core data from the wells to verify their accuracy. Porosity values for Wells X and Y fall within the range typically observed in sedimentary rocks, with Well Y having higher values. Hydrocarbons were detected in all reservoirs except reservoir zone 1b in both Well-X (12 reservoirs) and Well-Y (7 reservoirs). In Well- X, oil was identified in 5 reservoir zones while in Well-Y, oil was present in 2 reservoir zones. The remaining zones in both wells contained gas. To validate the results further, a comparison was made with the porosity of selected fields in the Niger Delta Basin and the general porosity of the Basin. Well X has a porosity range of 2.7% to 20.8%, which is generally lower than the reported porosity range Well Y has a porosity range of 19.90% to 24.38%, which falls at the upper end of the reported porosity range. Comparing previous works and data from other fields provides important validation for the findings of the study, which is crucial in the oil and gas industry for making informed decisions about exploration and production.

A Study on the Production Performance of a Horizontal Shale Gas Well Using a Fully Coupled Flow and Geomechanics Modeling

Conventional petroleum reservoir simulators use constant rock compressibility to denote rock deformation. However, due to the stress-sensitive nature of the shale formations, using constant rock compressibility in reservoir simulators does not accurately capture the pressure diffusion in the reservoir, leading to a higher error margin in flow rate estimation. Fluid flow coupling with geomechanics is used to account for such a phenomenon numerically. Such an approach is important for shale numerical studies and any energy underground storage modeling (i.e., CO2 storage). Usually, when fluid flow coupling with geomechanics is studied for shale formations, the fluid, and the stimulated reservoir petrophysical properties are overlooked. This paper aims to present a study on the effect of the fluid and reservoir petrophysical properties on the performance of a gas-producing well. In addition, the results from the cases when geomechanics is coupled and decoupled with fluid flow in reservoir simulations are compared. The governing equations were discretized using the Finite Element Method. First, the model was validated against Terzaghi's consolidation theory analytical solution. After that, a history matching for the production flow rate was performed using field production data from Barnett Shale. Then a sensitivity analysis was carried out for the gas viscosity, Stimulated Reservoir Volume (SRV) porosity, and fracture conductivity. Next, the sensitivity analysis was conducted for the coupled and decoupled cases. Finally, the sensitivity analysis results were compared between the coupled and decoupled cases. The results show that lower gas viscosity, higher SRV porosity, and higher fracture conductivity improved horizontal well production performance. In addition, when the geomechanical effects were decoupled, the reservoir simulator overestimated the production flow rate and cumulative production.

Effect of silica-based hybrid nano-surfactant on interfacial tension reduction for enhanced oil recovery

Crude oil production has considerably stabilized economic growth on a global scale. Unfortunately, the difficulties of oil production from a reservoir is being a global concern. Enhanced oil recovery (EOR) is one of the methods employed recently to increase oil production rate. Nanotechnology has been identified as one of the effective EOR techniques employed using nanoparticles (NPs) as a suitable candidates. Altering a reservoir's petrophysical property such as reducing interfacial tension (IFT) between crude oil and other liquids is an essential factor that plays a significant role in EOR. Considering the significant effects shown by silicon dioxide (SiO2) and iron dioxide (Fe2O3) NPs in EOR, the present study is aimed at investigating the influence of Fe2O3-SiO2 hybrid NPs supported with a surfactant on IFT. The hybrid NPs were produced and separately incorporated with surfactants of anionic sodium dodecylbenzene sulfonate (SDBS) and polyvinylpyrrolidone (PVP). The physical and chemical properties of the hybrid NPs were analyzed using X-ray diffraction (XRD) and Fourier transforms infrared (FTIR) spectroscopies, respectively. According to the results, the XRD pattern of the Fe2O3-SiO2 hybrid NPs displayed a crystalline structure of Fe2O3 NPs. The FTIR spectra of Fe2O3-SiO2 hybrid NPs showed characteristic absorptions of Fe2O3 and SiO2, indicating successful hybrid formation. The viscosity of Fe2O3-SiO2 nanofluids has increased from 0.95 to 1.85 cP. Upon introducing a hybrid nano-surface of SDBS and PVP, the viscosity values increased to 1.95 cP and 1.90 cP, respectively. Moreover, the Fe2O3-SiO2 hybrid NPs has reduced oil/brine/nanofluids IFT from 17.39 mN m−1 to 5.03 mN m−1. Additional reductions were observed when the surfactants were included. Consequently, IFT (mN m−1) was reduced from 17.39 to 3.08 for Fe2O3-SiO2-PVP and from 17.39 to 2.55 for Fe2O3-SiO2-SDBS. The finding of this study can help for a better understanding of the significant effect of silica-based hybrid nano-surfactant for IFT reduction which in turn could enhance oil production.

Full Scale of Pore-Throat Size Distribution and Its Control on Petrophysical Properties of the Shanxi Formation Tight Sandstone Reservoir in the North Ordos Basin, China

Abstract Pore-throat size distribution is a key factor controlling the storage capacity and percolation potential of the tight sandstone reservoirs. However, the complexity and strong heterogeneity make it difficult to investigate the pore structure of tight sandstone reservoirs by using conventional methods. In this study, integrated methods of casting thin section, scanning electron microscopy, high-pressure mercury intrusion (HPMI), and constant-pressure mercury intrusion (CPMI) were conducted to study the pore-throat size distribution and its effect on petrophysical properties of the Shanxi Formation tight sandstones in the northern Ordos Basin (China). Results show that pore types of the Shanxi tight sandstone reservoirs include intergranular pores, dissolution pores, intercrystalline micropores, and microfracture, while the throats are dominated by sheet-like and tube-shaped throats. The HPMI-derived pore-throat size ranges from 0.006 to 10 μm, and the pore-throats with a radius larger than 10 μm were less frequent. The pore body size obtained from CPMI shows similar characteristics with radii ranging from 100 to 525 μm, while the throat size varies greatly with radii ranging from 0.5 to 11.5 µm, resulting in a wide range of pore-throat radius ratio. The full range of pore size distribution curves obtained from the combination of HPMI and CPMI displays multimodal with radii ranging from 0.006 to 525 µm. Permeability of the tight sandstone reservoirs is primarily controlled by relatively larger pore throats with small proportions, and the permeability decreases as the proportions of smaller pore-throats increase. The pervading nanopores in the tight gas sandstone reservoirs contribute little to the permeability but play an important role in the reservoir storage capacity. A new empirical equation obtained by multiple regression indicates that r15 (pore-throat size corresponding to 15% mercury saturation) is the best permeability estimator for tight gas sandstone reservoirs, which yields the highest correlation coefficient of 0.9629 with permeability and porosity.

Applying Facies Characterization to Build 3D Rock-Type Model for Khasib Formation, Amara Oil Field

Building a rock-type (facies) model is critical in the process of constructing the geological model.The facies model utilizes the facies obtained from the different characterization methods to represent the structure and the geology of the studied reservoir. Therefore, the importance of building a 3D rock-type model is to distribute the petrophysical properties depending on the rock facies to reflect the actual distribution and achieve a realistic model.Khasib formation in Amara oil field is mainly composed of limestone and exhibits a high degree of heterogeneities in its petrophysical and geological features, showing a complicated porosity-permeability relationship. Hence, the formation should be characterized by facies with specific property relationships and use these facies to build an accurate rock-type model to represent the geological rock modeling for this carbonate formation.The Rock-Type model for Khasib formation has been constructed using the facies obtained from flow zone indicator and cluster analysis characterization methods, these facies were distributed with the PETREL software by applying the sequential indicator simulation (SIS) algorithm.The 3D Rock- type model establishes that a different rock type characterized each unit within Khasib formation; the reservoir units (KH11, KH12, and KH2) were characterized by the presence of RT-1, RT-2,andRT-3, which represent the best, good, and intermediate reservoir quality rocks, respectively. The best rock type RT-1 with the best reservoir petrophysical properties was only noticed in unit KH2. The non-reservoir units (Khasib, Base KH11, Base KH12, and Base KH2) were characterized by RT-4 and RT-5, which reflect the bad rock quality with non-reservoir properties.

The effects of porous medium parameters on electroseismic conversion

The generation of electroseismic conversion in fluid-filled porous media is closely related to reservoir parameters, however, its correlation and the influence of reservoir parameters on electroseismic conversion need to be clarified, and there is only a little analysis of measured electroseismic signals. In our study, we use experimental and theoretical methods to investigate the dependency of the reservoir parameters on the electroseismic coupling. A set of experimental devices was built to conduct electroseismic measurements on water-saturated sandstone samples. The electroseismic theory based on the capillary model is used to comprehensively analyze the experimental results and explore the effects of reservoir parameters (porosity, permeability, fluid concentration) on electroseismic conversion. The combined experimental and theoretical analysis show that the electroseismic signal increases with porosity, but its relationship with permeability is complicated. In the lower permeability range, the electroseismic conversion firstly increases with the increase of permeability, while continued increases of permeability lead to a decrease in electroseismic conversion in the high permeability range. The dependency of the electroseismic conversion on pore fluid concentration also presents two trends in different concentration ranges. It decreases rapidly with the increase of fluid concentration in the low concentration range. When the intensity of electroseismic conversion reaches the minimum, it remains almost unchanged even if the fluid concentration continues to increase. The results of the influence of reservoir parameters on electroseismic conversion indicate that electroseismic conversion is as sensitive to the parameters of fluid-filled porous media as seismoelectric conversion. The electroseismic conversion signal is more stable than seismoelectric signal, which means that compared with the difficult detection of seismoelectric signals, the detectability of electroseismic signals is higher. It may be easier to use electroseismic signals to reveal the petrophysical properties of reservoirs.

Study on factors affecting the petro physical properties of sandstone and conglomerate reservoirs of Baikouquan Formation, Junggar Basin

In recent years, oil and gas exploration of the Baikouquan Formation in the northwestern margin of the Junggar Basin has seen major breakthroughs have been made in oil and gas exploration. Sandstone and conglomerate reservoirs are developed in the Baikouquan Formation in this area, but the factors affecting the differences in petro physical properties of these two types of reservoirs are still unclear. In this paper, taking the Baikouquan Formation in the Hongcheguai area on the northwestern margin of the Junggar Basin as an example, a large number of core observations, thin sections, scanning electron microscopy, and petro physical property test data were used to evaluate the petro logical characteristics, reservoir space types, digenesis and pore evolution of the sandstone and conglomerate reservoirs. The results show that the sandstone and conglomerate rocks of the Baikouquan Formation in the study area have a large content of tuffaceous components. The sandstone reservoirs are dominated by primary intergranular pores, and the conglomerate reservoirs are dominated by secondary dissolved pores. In addition, the porosity is negatively correlated with rock permeability for the conglomerate rocks of the Baikouquan Formation. However, the porosity is positively correlated with rock permeability of the sandstone reservoirs. According to the analysis of the digenetic process, the compaction and cementation can lead to a significant decrease in the petro physical properties of the reservoir. While dissolution can improve the petro physical properties of the sandstone reservoirs to a small extent, and can improve that of the conglomerate reservoirs to a greater extent. Moreover, local fractures are important factors affecting the petro physical properties of the conglomerate reservoirs. The existence of abnormal high pressure has a certain effect on the preservation of primary pores. On the whole, the controlling factors of the petro physical properties of the conglomerate reservoirs in the Baikouquan Formation include sedimentation, diagenesis, and tectonic actives, while that of the sandstone reservoirs mainly include sedimentation and diagenesis.

Impact of salt deposition induced by water evaporation on petrophysical properties and pore structure in underground gas storage through dynamic and static experiments

During the production process of underground gas storage (UGS) with high-salinity formation water, salt deposition has been observed due to formation water evaporation. This work aims at understanding the effect of salt deposition on petrophysical properties and pore structure. Firstly, dynamic and static experiments are carried out to simulate the multi-cycle gas injection and production of the UGS based on the core plugs, rock debris and water from Wen23 gas field. Secondly, Nuclear magnetic resonance (NMR), scan electron microscope (SEM) and energy dispersive spectrum (EDS) are applied to investigate the change of pore structure and salt-crystal morphology. Results indicate that the core permeability and porosity after water evaporation are averagely increased by 39 % to 68 % and 42 % to 66 % respectively compared with the initial water saturation conditions under different water salinity. Salt crystals in the reservoir are mainly deposited in large pores. The dispersed and aggregated salt crystals are observed and most salt crystals are between 1 μm and 5 μm in size. Thus, formation water evaporation is beneficial to the improvement of reservoir petrophysical properties without formation water supplement. This work provides an effective method to understand the impact of salt deposition caused by formation water evaporation on the petrophysical properties, fluid flow ability, and gas storage capacity of the UGS and CO2 geological storage.

Modelling temperature dynamics of the SAGD process in an oil reservoir by the discovery of parametric partial differential equations

AbstractMany chemical and industrial processes are complex, and the dynamics of such processes cannot be explained using a partial differential equation (PDE) or a system of PDEs with constant coefficients. Parametric PDEs, that is, PDEs with their coefficients varying across time or space, are utilized for this purpose. The non‐availability of data at all spatial locations and partially available process knowledge add to the complexity of modelling such processes. This paper proposes a framework to discover parametric PDEs using data‐driven and hybrid modelling approaches with the temperature dynamics of steam‐assisted gravity drainage (SAGD) process in an oil reservoir as the system under study. We utilize an ensemble of 200 realizations of the temperature dynamics generated using the variogram for the PDE discovery. Permeability, which is one of the oil reservoir's petrophysical properties, is used to develop the hybrid models. We infer that utilizing partial process knowledge aids in improving the model's accuracy.

Evaluating the sedimentological and diagenetic impacts on terrestrial lacustrine fan delta sandy conglomerates reservoir quality: Insights from the Triassic Baikouquan Formation in the Mahu sag, Junggar Basin, Western China

The terrestrial lacustrine fan delta conglomerate reservoirs in the Triassic Baikouquan Formation (BF) are the primary hydrocarbon exploration targets in the Mahu sag, Junggar Basin, Western China. However, the varying lithofacies and complex diagenesis controlling the reservoir quality remain poorly understood. For the sake of revealing how reservoir quality is associated with sedimentary processes and diagenetic alterations, we used integrated approaches like petrographical analysis, cores description, wireline, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury intrusion capillary pressure (MICP) and measured petrophysical properties. The results showed that sedimentary processes have considerable control over facies distribution, grain size, and clay content, causing spatial variation of reservoir quality within the fan delta deposits. The coarser grain and high clay content fraction at the base of gravity flow will first settle in the fan delta plain near provenance, whereas the finer grains at the top of flows progressively deposit in the fan delta front areas. From proximal to distal fan delta, a progressive conversion from cohesive muddy debris flow into traction current can be inferred from the variations of lithofacies associations. A total of 8 types of microfacies were identified where the conglomerates of the BF were deposited. The grayish-green fine-grained conglomerates concentrated in the subaqueous distributary channels provide the best reservoir performance, whereas debris flow deposits dominated primarily by muddy debrites occupy the worst reservoir quality because of their highest clay content and coarsest grain size.The dominant diagenetic events include mechanical compaction that continued throughout the entire burial, two phases of quartz cementation, dissolution of unstable components, early and late carbonate cementation, precipitation of authigenic clay minerals, and two phases of hydrocarbon charging. It is unveiled that compaction is the predominant mechanism negatively affecting reservoir quality in the fan delta complex, while the effect of cementation on pore reduction of the conglomerate reservoir is weaker than compaction. Simultaneously, a complex relationship exists between reservoir petrophysical properties within different clay minerals. Dissolution does not significantly improve the permeability of the reservoir because of the partial dissolution which primarily generated intragranular pores with strong heterogeneity and poor connectivity. The most favorable reservoirs occur primarily in the subaqueous distributary channels in the fan delta front, which comprise well-sorted fine-grained conglomerates with well-developed residual intergranular pores and secondary dissolution pores and have undergone two phases of oil charge. This work may provide a useful reference for hydrocarbon exploration of the fan delta systems and regions which have encountered similar sedimentary and diagenetic processes.