Reservoir Rocks Research Articles

The 15 January 2022 Hunga (Tonga) eruption: A gas-driven climactic explosion

An extraordinarily powerful, explosive eruption occurred from Hunga volcano in the Tonga island arc on 15 January 2022 and generated an eruption column 58 km high. The explosive eruption also generated atmospheric gravity waves, extreme runup tsunamis and quite unusual and destructive meteotsunamis. Together these place this VEI 6 eruption as, globally, one of the largest of the past 300 years.Based on the oceanic context of Hunga volcano, it has previously been assumed that the eruption was phreatomagmatic through a fuel-coolant Surtseyan-type interaction, but this is not supported by satellite imagery. Similarly, it has been suggested that a caldera-collapse was the eruption trigger, but this is not supported by bathymetric data or the seismicity recorded during the eruption. Here we develop a new model based on the observed energetics and time sequence of the eruption integrated with understanding of the internal structure of active volcanoes and their characteristic high flux discharges of volcanic gas.It has been shown elsewhere that magma-derived reactive gases (H2O, CO2, SO2, HCl, etc) aggressively alter the volcanic rocks in the core of a volcano leading to self-sealing of gas flow to the surface and consequent changes to deviatoric stress in the structure. Common minerals developed by these reactions include anhydrite (CaSO4), sulphides and silica (quartz), all of which have been recorded in volcanic ejecta including at Hunga.We here develop a first order numerical model that quantifies how the free discharge of such gas to the surface may progressively become choked by these sealing reactions leading to increased internal gas pressure. Hydraulic fracture of the seal occurs when the transmitted pressure of the compressed magmatic gas beneath the seal increases to a value greater than the lithostatic pressure plus the tensile strength of the sealed rock. This initiates the explosive release of compressed gas whose high-power discharge progressively develops and enlarges a crater. At the same time, the explosion feeds upon itself by generating larger pressure gradients in the pressurized gas within the fractured porous rock mass of the core of the volcano. Excavation of the crater may intersect high level intrusions and produce the pumice rafts that were observed after the eruption. The eruption itself diminished in intensity as the gas pressure in the reservoir declined.At Hunga, the eruption excavated an 850 m deep, 2-3 km diameter steep-walled crater. This volume may be assumed to approximate the volume of fractured porous rock (the control volume of the eruption) whose trapped gas was mined by the eruption until surrounding gas pressure was depleted. Our numerical model shows that the calculated potential energy of the trapped compressed gas matches the independent observations of the scale of the eruption. Sensor data have since shown that gas bubble flares continued for at least 6 months after the eruption indicating continued depletion of the gas reservoir of rocks surrounding the new crater. The systems-based, gas-driven model for the Hunga climactic eruption developed here also applies to Plinean-type eruptions on subaerial arc volcanoes such as at Pinatubo (Philippines) 1991.

Laboratory Investigation on Permeability Change and Economic Analysis Using Some Selected Nanoparticles for Enhanced Oil Recovery

Enhanced oil recovery using nanoparticles is an emerging technique that can potentially alter permeability and wettability of porous media for improved oil mobilization. This study experimentally investigates the permeability alteration caused by three commonly used nanoparticle types – copper (ii) oxide, zinc oxide and silicon oxide. Core flooding experiments were conducted on reservoir rock samples before and after treatment with nanoparticle dispersions. Results show decrease in permeability by 35% for copper (ii) oxide, 30% for zinc oxide and 10% silicon oxide respectively. Pore-scale analysis indicates that permeability change occurs through mechanisms like pore throat blocking/wettability alteration. Nanoparticle concentration is also found to influence the permeability variation, with optimal dosage. Among the systems tested, Silicon oxide is the most effective formulation for enhancing oil recovery applications based on its ability to recover oil with minimal alteration to formation permeability. From the result, Silicon oxide had a cumulative recovery of 17ml, 18.0ml and 18.5ml thereby generating a percentage recovery of 73.91%, 78.26% and 80.43% while Zinc oxide had a cumulative recovery of 15.5ml, 18.0ml and 16.5ml thereby generating a percentage recovery of 77.50%, 78.26% and 71.74ml%, lastly Copper (ii) oxide had a cumulative recovery of 16.5ml, 17.0 and 16.0 generating a percentage recovery of 75%, 73.91% and 72.72% respectively with a concentration of 0.1%, 0.3%, and 0.5%. This study demonstrates the potential of Silicon oxide nanoparticles for enhanced oil recovery through permeability manipulation in porous media, however, the economic analysis shows that it’s quite expensive due to its cost of production and won’t be ideal for use. Hence Zinc oxide which also has a high volume of oil recovery, and less production cost can be used.

Quantification of hydrogen depletion and mineral reactivity in underground hydrogen storage reservoirs

The utilisation of renewable energy has surged over the past decades due to shifts in climate patterns and the diminishing reserves of fossil fuels. Among the renewables, hydrogen energy has emerged as a promising clean energy carrier in recent years. In the hydrogen industry, storage faces a notable hurdle due to the relatively low density of hydrogen gas (0.0813 kg/m³ at 25 °C and 1 atm) and its lower storage density (7–27 kg/m³ at 25 °C and 100–400 atm). As a potential remedy, underground hydrogen storage emerges as a viable option, even though it is not without its challenges. Among these challenges, a prominent one involves the diversity in the composition and physical properties of the reservoir due to the influence of both biological and geo-chemical reactions. In this study, an extensive modelling effort was undertaken to gain insights into the impact of both bio and geo-chemical reactions, variations in porosity, hydrogen depletion, and the effects of diffusion across various levels of salinity, pressure, and temperature. Diverse Water/Rock ratios, distinct minerals, and residual gases were also considered. The modelled conditions encompassing mineral properties and parameters led to a cumulative hydrogen loss of 8.38% over a century. From this, 2.31% was identified due to the reactivity in reservoir rock and 6.07% due to the aqueous diffusion to cap rock and its reactivity. Among these reactions, carbonate dissolution emerged as the most noteworthy, resulting in considerable hydrogen loss contingent upon the presence of methanogenesis bacteria. As per the modelled scenario, porosity was reduced in reservoir rock by 0.41%, and in carbonate cap rock, it was increased by 56%, which could increase the hydrogen leakage. Also, methane (CH4) exhibited the most favourable characteristics as a cushion gas due to its lower reactivity. However, it's crucial to acknowledge that these figures could significantly fluctuate based on variations in mineral composition, bacterial populations and their growth, and the prevailing subsurface conditions. These modelled findings can serve as a valuable tool for comprehending the mechanisms of hydrogen loss and mineral reactivity within a given underground system.

Spontaneous Imbibition and an Interface-Electrostatics-Based Model of the Transition Zone Thickness of Hydrocarbon Reservoirs and Their Theoretical Interpretations

The transition zone (TZ) of hydrocarbon reservoirs is an integral part of the hydrocarbon pool which contains a substantial fraction of the deposit, particularly in carbonate petroleum systems. Consequently, knowledge of its thickness and petrophysical properties, viz. its pore size distribution and wettability characteristic, is critical to optimizing hydrocarbon production in this zone. Using classical formation evaluation techniques, the thickness of the transition zone has been estimated, using well logging methods including resistivity and Nuclear Magnetic Resonance, among others. While hydrocarbon fluids’ accumulation in petroleum reservoirs occurs due to the migration and displacement of originally water-filled potential structural and stratigraphic traps, the development of their TZ integrates petrophysical processes that combine spontaneous capillary imbibition and wettability phenomena. In the literature, wettability phenomena have been shown to also be governed by electrostatic phenomena. Therefore, given that reservoir rocks are aggregates of minerals with ionizable surface groups that facilitate the development of an electric double layer, a definite theoretical relationship between the TZ and electrostatic theory must be feasible. Accordingly, a theoretical approach to estimating the TZ thickness, using the electrostatic theory and based on the electric double layer theory, is attractive, but this is lacking in the literature. Herein, we fill the knowledge gap by using the interfacial electrostatic theory based on the fundamental tenets of the solution to the Poisson–Boltzmann mean field theory. Accordingly, we have used an existing model of capillary rise based on free energy concepts to derive a capillary rise equation that can be used to theoretically predict observations based on the TZ thickness of different reservoir rocks, using well-established formation evaluation methods. The novelty of our work stems from the ability of the model to theoretically and accurately predict the TZ thickness of the different lithostratigraphic units of hydrocarbon reservoirs, because of the experimental accessibility of its model parameters.

Kinetics mechanism of pore pressure effect on CO2-water-rock interactions: An experimental study

Carbon capture, utilization and storage (CCUS) is an effective technology to reduce carbon dioxide (CO2) content in atmosphere, while due to the insufficient mastery of deterioration laws of reservoir rocks caused by CO2, the extensive application of carbon storage projects is hindered by the leakage risk. Therefore, it was aimed to study the kinetics mechanism of pore water pressure on CO2-water–rock interactions. First, the pressure effect on water–rock interactions was studied to obtain the relationship between ratio of solid–liquid contact area Ψ and pore pressure, and the controlling mechanism of Ψ on reaction rate ri was verified. On this basis, the pressure effect on CO2-water–rock interactions was further studied. Considering the effects on Ψ and solution acidity, the original CO2-applicable kinetics equation was modified to reduce the error of calculating reaction rate by 33.60% on average. Meanwhile, a forecast method was proposed for the reaction rate under different pressure conditions, and the average calculation error was 41.00% lower than that of original kinetics equation. After verifying the accuracy of these two theoretical methods to calculate reaction rate, the reliability to calculate porosity evolution process was further verified, and the calculation errors could be reduced by 29.52% and 31.81%, respectively.

Investigating the CO2 injection and the performance of nanoparticles in preventing formation damage at different pressures and concentrations

AbstractAsphaltene deposition is one of the main challenges during CO2 injection (miscible or immiscible) into reservoirs. Asphaltene deposition reduces the porosity and permeability of reservoir rock and changes its wettability to strongly oil‐wet. In this article, to control the asphaltene deposition during CO2 injection the use of direct asphaltene inhibitors (Al2O3 and Fe3O4) in reservoir conditions. In this research, nanoparticle screening (to investigate its significance in reducing asphaltene precipitation) has been done and it can be stated that Al2O3 nanoparticle will perform better effectivity than Fe3O4 nanoparticle. After that, by using effective nanoparticles (Al2O3) in different concentrations (1000 and 2000 ppm), the amount of asphaltene deposition during CO2 injection has been investigated. The obtained results show that increasing the injection pressure (from immiscible to miscible) causes an increase in asphaltene deposition and the use of nanoparticles will reduce the amount of asphaltene deposition.

Time and mechanism of formation of mud volcanoes in the South Caspian basin according to seismic data

There are 277 mud volcanoes located in the South Caspian basin and the Apsheron-Gobustan periclinal trough and the Lower Kura depression that open to it. On land there are 177 mud volcanic structures, from which steam, water, mud, gas and oil are constantly erupting at approximately 500 points. Mud volcanoes located in the Caspian Sea (about 100) also play an important role in the degassing (mainly methane) of the sedimentary layer of the earth’s crust. Based on the results of geological and geophysical research, it has been established that almost all mud volcanoes discovered on the territory of Azerbaijan are associated with hydrocarbon deposits. In the Oligocene – Lower Miocene, mainly in the Maikop time, a thick clayey stratum (Maikop) - source rocks – accumulated in the South Caspian depression. At the end of the Miocene, there was a sharp drop in erosion levels in this basin. As a result of the activity of several river systems (Pleo-Volga, Paleo-Kura, Paleo-Pirsagat, Paleo-Amu Darya) over the Maikop clay deposits, a system of alternating layers of low and high density was formed with a total thickness of sediments of eight kilometers or more. The Maikop clay formations buried under this multilayer system, possessing the properties of a non-Newtonian fluid, created intrusions in the overlying environment, which at subsequent stages of development of the sedimentation basin became eruptive channels of mud volcanoes. The results of research using 3D seismic data made it possible to identify the mechanism of formation of mud volcanism, which, according to the authors, is associated with the migration of hydrocarbons from oil and gas source rocks to reservoir rocks, with the channels of mud volcanoes being considered as the main migration routes. Geological interpretation of seismic data shows that the formation of mud volcanoes in the South Caspian basin supposedly began from the beginning of the Miocene and continued in parallel during subsequent periods of development of the sedimentation basin. As the thickness of the sedimentary cover increased, mud volcanoes periodically became active.

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

Novel hybrid coaxial-U-shaped closed-loop geothermal system for enhanced energy extraction: a numerical analysis

ABSTRACT Insulated U-shaped closed-loop geothermal system (UCLGS) is an efficient and environmentally friendly method of harnessing geothermal energy. However, heat available in the rock surrounding the insulated production pipe has not been extracted yet. Therefore, this study proposed a novel hybrid coaxial-U-shaped CLGS (HCLGS) to enhance the overall thermal performance of CLGS. The HCLGS comprises an insulated UCLGS for harnessing energy from the reservoir rock, alongside a coaxial double pipe system designed to extract additional thermal energy from the rock enveloping the insulated production pipe of the UCLGS. Further, the study explored the thermal feasibility of the proposed HCLGS in various rock formations for geothermal energy extraction at different depths. The results showed that the HCLGS installed in the pyroxenite rock produced primary hot fluid with a maximum temperature of 94°C and secondary hot fluid at a temperature of 38.5°C for the base case, achieving a COP of 1.15. The proposed HCLGS can extract up to 18% higher thermal power than the insulated UCLGS, with a COP ranging from 1.11 to 1.16. Finally, the proposed hybrid system significantly harnessed the additional heat available in the rock encompassing the insulated production pipe of UCLGS.

Evaluating Source, Scale Risk, and Corrosion Risk of the Produced Water Samples from the Appalachian Basin Based on a Geochemical Database

Summary Statistically, oil and gas production can generate up to 20 times the oil equivalent of produced water. The composition of produced water samples reflects its source, its interactions with reservoir rocks, and downhole (DH) facilities, which are critical for basin evolution, water source determination, and the monitoring, management, and optimization of oil and gas production. For example, scale and corrosion, two of the most severe flow assurance issues accompanied by produced water, can lead to billions of dollars lost every year. However, few studies have developed a standard protocol to extract such valuable information from produced water compositions due to a lack of data and professional models. Using produced water geochemical data from the Appalachian Basin, one of the largest natural gas producers in the US, from the United States Geological Survey (USGS) Produced Waters Geochemical Database (PWGD), we developed a standard protocol to investigate the produced water source, evolution history, and scale and corrosion risks under both DH and surface conditions by means of incorporating the professional models for water-rock interaction and corrosion. The results show that the produced water from the Appalachian Basin possibly evolves from seawater evaporation following a typical evolution pattern of ion concentration and water isotopes, while a group of time-elapsed samples indicates that such an evolution pattern can also be due to the mixture of the injected water and reservoir water. In addition, most produced water samples show obvious risks of mineral scaling (e.g., calcite, barite, and siderite) and CO2 corrosion with corresponding mitigation strategies recommended. This study not only developed a reliable data processing and analysis protocol but also showed the valuable information a systematic analysis of produced water samples can provide for actual oil and gas production.

An Analytical Relative Permeability Model Considering Flow Path Structural Characteristics for Gas-Liquid Two-Phase Flow in Shale Fracture

Summary Relative permeability models are essential in describing the multiphase fluid flow in reservoir rocks. Literature work has shown that the existing theoretical models of relative permeability cannot perfectly describe the two-phase flow experimental data in fractures because those models are mostly developed for porous media (such as sandstone) or proposed without fully taking the specific characteristics of two-phase flow into consideration. In this paper, we propose a theoretical two-phase flow relative permeability model based on the tortuous flow channels, considering the structural characteristics of two-phase flow in the fractures. This model considers that the gas and liquid flow through different channels of different shapes and sizes at the same time. The formula for two-phase relative permeability was derived from cubic law in fracture and Darcy’s law, with the influence of the slip effect of the gas phase also considered. The results from different models were compared using several series of experimental data. The model proposed in this paper has a better fit than the others for the raw experimental data. This study demonstrates that it is crucial to take the flow paths and distribution of the two phases into consideration to model the two-phase flow in fracture accurately. This work also found that the tortuosity of the gas channel at the irreducible liquid saturation has a negative effect on gas relative permeability but positive to liquid relative permeability. Moreover, the model demonstrates that the decrease in aperture leads to an increase in the gas relative permeability due to gas slippage, while the impact of gas slippage reduces under high pressure.

Simulation of dynamic pulsing fracking in poroelastic media by a hydro-damage-mechanical coupled cohesive phase field model

This study develops a hydro-damage-mechanical fully coupled numerical method capable of modelling complex fluid-driven transient dynamic crack propagation in quasi-brittle poroelastic media. In this method, the fluid flow in both fractures and porous media is described by a fluid continuity equation with the modified Darcy-Poiseuille law based on the Biot's poroelastic theory. The fluid pressure and the inertial force of solids are coupled by governing equations of the mesh-insensitive phase-field regularized cohesive zone model that can simulate quasi-brittle multi-crack initiation, propagation, branching and merging without remeshing or crack tracking. The resultant displacement-pressure-damage coupled multiphysics system of equations is solved using an alternative minimization Newton-Raphson iterative algorithm with an implicit Newmark integration scheme within the finite element framework. The new method was first validated by a few 2D problems, including crack branching and deflecting in solids, fracking in a concrete cube, and consolidation and stress wave propagation in poroelastic media, subjected to various impulsive loadings. It was then applied to pressure pulsing fracking of a 40 m granite rock reservoir with extensive parametric studies of fluid viscosity and pulsing injection rate, mode and period. It was found that pulsing injection with higher fluid rates and lower fluid viscosities resulted in more developed crack patterns, and in particular, there existed an optimal pulsing injection period that could promote fracking under relatively low injection pressures. 3D horizontal well problems with multiple non-planar crack propagation and bifurcation were also successfully simulated to demonstrate the capacity and potential of the new method for engineering design and optimization of pressure pulsing fracking.

Reservoir rock typing for optimum permeability prediction of Nubia formation in October Field, Gulf of Suez, Egypt

Permeability prediction and distribution is very critical for reservoir modeling process. The conventional method for obtaining permeability data is from cores, which is a very costly method. Therefore, it is usual to pay attention to logs for calculating permeability where it has massive limitations regarding this step. The aim of this study is to use unique artificial intelligence (AI) algorithms to tackle this challenge and predict permeability in the studied wells using conventional logs and routine core analysis results of the core plugs as an input to predict the permeability in non-cored intervals using extreme gradient boosting algorithm (XGB). This led to promising results as per the R2 correlation coefficient. The R2 correlation coefficient between the predicted and actual permeability was 0.73 when using the porosity measured from core plugs and 0.51 when using the porosity calculated from logs. This study presents the use of machine-learning extreme gradient boosting algorithm in permeability prediction. To our knowledge, this algorithm has not been used in this formation and field before. In addition, the machine-learning model established is uniquely simple and convenient as only four commonly available logs are required as inputs, it even provides reliable results even if one of the required logs for input is synthesized due to its unavailability.

Numerical simulation of multi-field coupling in geothermal reservoir heat extraction of enhanced geothermal systems

The coupled analysis of multi-field heat and mass transfer in geothermal reservoirs is a pivotal concern within the realm of geothermal rock exploitation. It holds significant implications for the assessment of thermal energy capacity and the formulation of reservoir optimization strategies in the context of geothermal rock resources. Parameters governing production, along with fracture network characteristics (such as injection well temperature, injection well pressure, fracture width, and fracture network density), exert an influence on enhanced geothermal systems (EGS) heat production. In this study, aiming to comprehend the dynamic heat generation of EGS during prolonged exploitation, a coupling of various fields including permeation within the rock formations of geothermal reservoirs and the deformation of these rocks was achieved. In this study, we formulated the governing equations for the temperature field, stress field, and permeability field within the geothermal reservoir rock. Subsequently, we conducted numerical simulations to investigate the heat transfer process in an enhanced geothermal system. We analyzed the effects of injection well temperature, injection well pressure, primary fracture width, and secondary fracture density on the temperature distribution within the reservoir and the thermal power output of the production well. The research findings underscore that ill-conceived exploitation schemes markedly accelerate the thermal breakthrough rate of production wells, resulting in a diminished rate of geothermal resource extraction from the geothermal reservoir rock. Variations in influent well temperature and secondary fracture density exhibit an approximately linear impact on the output from production wells. Crucially, injection well pressure and primary fracture width emerge as pivotal factors influencing reservoir output response, with excessive widening of primary fractures leading to premature thermal breakthrough in production wells.

An experimental study on mechanical properties and fracturing characteristics of granite under high-temperature heating and liquid nitrogen cooling cyclic treatment

Liquid nitrogen (LN2) fracturing is a promising technology for efficient development of hot dry rock reservoir geothermal resources. To investigate the cracking mechanism of LN2 on high-temperature granite, heating and LN2 cooling cyclic treatment were applied to granite samples. Based on Brazilian splitting test, and different methods were employed to describe the crack propagation and failure mechanism, including acoustic emission monitoring, laser profile scanning, and scanning electron microscopy. The results demonstrate that heating and LN2 cooling cyclic treatment deteriorates the mechanical properties of granite. Specifically, after 20 cycles, the average P-wave velocity of the samples decreases by 34%, with the amplitude of the waveform decreasing from 130 dB to 50 dB. Moreover, the uniformity and integrity of the waveform worsen after cyclic treatment. The tensile strength, peak strain, and brittleness index of granite samples decrease with cycle numbers. From 3 to 20 cycles, the absorbed energy of the samples reduces by 53%, with thermal damage reducing the energy storage limit. The cyclic cooling treatment of LN2 increases the surface roughness and width of crack of the samples, resulting in obvious plastic failure at both ends of the samples. Furthermore, the height parameter Sa and area ratio Sdr of the fracture surface increase by 53.8% and 69.5%, respectively, as the number of cycles increase from 3 to 20. Additionally, the fractal dimension of the granite samples increases from 2.155 to 2.181, indicating an increase in the complexity of the cross-section. Following heating and LN2 cooling cyclic treatment, the failure mode of granite changes from vertical splitting to shear failure, with decreased brittleness and increased plasticity and ductility.

Development of a New Correlation for Predicting Initial Water Saturation in Carbonate Reservoirs

The Middle East, rich in oil and gas within carbonate rocks, accounts for a significant portion of global reserves, drawing extensive exploration by major oil firms. Unlike Southeast Asia's fracture and cavity-dominated carbonate reservoirs, the Middle East features thick-bedded, pore-structured reservoirs with vast reserves. These complex and varied pore structures cause reservoir inhomogeneity, challenging the technical evaluation of these unconventional reservoirs. Characterization of carbonate reservoirs differs in terms of their mineralogical compositions and heterogenous pore systems from that of clastic reservoirs. Reservoir characterization seeks to build geological and petrophysical models for reservoir simulation. Rock types represent the most crucial characteristics of reservoirs for specialized facies modelling within specific ranges of porosity and permeability. Rock typing is an essential method routinely used by petroleum engineers for characterizing and predicting the reservoir quality of carbonate reservoirs by classifying reservoir rocks into distinct units based on similar petrophysical properties. It is imperative to predict these reservoir properties accurately and precisely. The J-function technique is considered the most effective rock typing procedure. In this study, a new correlation for predicting initial water saturation (Swi) for a reservoir producing from a Permian carbonate formation, located in the Arabian Peninsula, has been developed. The new empirical equation is an augmented Lucia model that utilizes capillary pressure (P�), porosity (), and permeability (k), as independent variables. The coefficient of multiple R2 , the student’s t and F-tests p-value were used in the model evaluation. R2 for the new model was about 0.92, t-test and F-test p-values were much lower than 0.05, indicating that the independent variables are significant. The model was also tested against an independent data set and yielded an R2 of 0.88. Likewise, the new correlation was compared to Lucia’s model and showed better results. The goal of the study is to use the developed correlation in the geostatistical modeling of connate water saturation for analogous formations in the region.

Molecular dynamics simulation and key performance study of VES self-diverting acid system for deep carbonate reservoirs

Viscoelastic Surfactant (VES) self-diverting acid technology is an ideal approach for enhanced recovery from heterogeneous reservoirs. Most VES self-diverting acid systems currently used in field operations are only suitable for low-temperature reservoirs, and research on self-diverting VES acid systems for deep carbonate rock formations is lacking. Additionally, studies on the molecular dynamics of the self-assembly of VES have mainly focused on cationic surfactants, with insufficient research on the self-assembly of betaines in the oil industry. This study investigated the effects of temperature, surfactant concentration, and metal ion concentration on the self-assembly of erucamide propyl hydroxysulfobetaine (EHSB) based on a self-assembly model through molecular simulation methods. Moreover, the viscosity of the EHSB was predicted under various conditions. The results indicated that the system viscosity was optimal at an EHSB concentration of 4 wt%. The EHSB system requires initiation by metal ions to enhance the viscosity, with Ca2+ having a more pronounced effect than Mg2+. This is attributed to the formation of a unique “octahedral” structure by Ca2+ in solution, which aids in the formation of large micelles. Furthermore, because of the smaller ionic radius of Mg2+ compared with that of Ca2+, Mg2+ is more likely to penetrate micelles and form salt bridges, promoting a tighter arrangement of surfactant molecules. Based on molecular simulation and laboratory experiments, under optimal concentrations of inorganic salts and EHSB, the system’s viscosity remained greater than 150 mPa·s at 140 °C, meeting the requirements for diversion in deep carbonate rock formations. Finally, the acidization capacity and diversion effects of the acidic system were demonstrated using single-core flood and dual-core diversion experiments. The results showed that the acid solution significantly etched the core, and the residual acid reduced the permeability contrast of the core from 3.54 to 2.35, indicating a good acidizing diversion performance. This study utilizes a combination of computer simulations and laboratory experiments to optimize a VES self-diverting acid system. The computer-predicted viscosity corresponds well with the actual measured viscosity, providing new technical insights for evaluating the performance of VES under complex formation conditions that are unattainable through laboratory tests. A self-diverting VES acid system suitable for deep carbonate rock reservoirs at 140 °C was developed, providing technical support for the efficient development of deep carbonate reservoirs.

Diagenetic evolution and origin of cements of the Cretaceous carbonates in the Akal Block, southeast Gulf of Mexico

The Cretaceous succession of deep marine facies (580 m-thick) of the Akal Block, southeast of the Gulf of Mexico, is dominated by lime mudstones that have been extensively affected by dolomitization. Petrographic examination, including cathodoluminescence (CL), and microthermometry reveal three phases of dolomitization that occurred as replacement and pore-/fracture-filling cements. These are (1) an early replacement dolomicrite (D1, <50 μm) with dull orange CL, (2) eu-to subhedral dolomite (D2, 60 μm–150 μm) with distinctive cloudy cores (dull CL) and clean edges (non-luminescent to dull CL), and intercrystalline porosity (6 %), and (3) anhedral vug-/fracture-filling dolomite (D3, 200 μm–500 μm) exhibiting CL zonation. The mean δ18O values of those dolomites show a trend of slight decrease from D1 to D3 (D1 = 0.0 ± 1.3‰ VPDB, D2 = −0.2 ± 1.1‰ VPDB, D3 = −1.2 ± 1.6‰ VPDB), which reflects the influence of progressive burial. The low Sr contents (101 ± 29 ppm) of D1, along with its near-micritic grain size and estimated δ18OD1fluid of parent dolomitizing fluid (−3.6‰–1.9‰ SMOW), support early-stage dolomitization at low temperature of near-surface conditions from solutions of mixed meteoric and seawaters. The higher estimated δ18Ofluid values of D2 and D3 (3.0–13.9‰ SMOW) are expected for fluids in burial settings of high temperatures. The homogenization temperatures of the primary two-phase fluid inclusions of D2 (Th = 99.1 ± 7.9 °C) and D3 (Th = 89.5 ± 11.2 °C) suggest precipitation at deeper burial settings, which is also consistent with their lower Sr contents (80 ± 14 ppm and 98 ± 33 ppm, respectively). The lower mean Th value of D3 than that of D2 likely reflects the influence of tectonic uplift that affected the Akal Block. The shale-normalized (REESN) patterns of the dolomites mimic that of modern seawater and those of D1 and D2, in particular, coincide with that of the lime mudstones (C1), thus suggesting that C1 was their precursor and also D3 originated almost from the same parent fluid that its geochemical composition evolved with progressive burial. The latest fracture-filling calcite cement (C2) postdated D3. The investigation of the products of burial diagenesis, such as fracturing, dissolution, and dolomitization events and their relationship with the tectonic uplift of the Akal Block allows a better understanding of the factors controlling the quality of Cretaceous reservoir rocks.

Reciprocal cross‐correlation analysis of two‐phase seepage processes and reservoir heterogeneities in CO2 saline aquifer sequestration

AbstractWhen CO2 saline aquifer storage is carried out, the heterogeneity of reservoir rock is an important factor affecting CO2 transport, and the reservoir heterogeneity in numerical simulations is mainly manifested as the heterogeneity of the parameter field. Since the parameter distributions across the reservoir are not available with the existing probes, the stochastic finite element method is combined with a two‐phase flow model to establish an unconditional random field of permeability, and computations are performed using the Monte Carlo method. The permeability, CO2 maximum migration distance (Md) and CO2 sweep area (Sa) were analyzed for mutual correlation. The permeability correlation area affecting Md and Sa was obtained, and the changes in the correlation area under the coefficient of variation (Cv) and correlation length (λx) of the permeability field in the different reservoirs were analyzed. The kriging superposition approach (KSA) was subsequently used to estimate both the Md and Sa of the target reservoir by establishing conditional random fields based on the sampling parameters in regions with different correlations, resulting in errors of 0.66% for Md and 0.96% for Sa in the high correlation region and 4.86% and 3.12% for Md and Sa in the low correlation region, which suggested that the sampling results from the high correlation region were less biased in the estimation. Under limited sampling conditions, it is recommended that samples be collected in regions with high correlations to reduce the uncertainty of CO2 transport analysis due to unknown heterogeneity. © 2024 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

Enrichment model and major controlling factors of below-source tight oil in Lower Cretaceous Fuyu reservoirs in northern Songliao Basin, NE China

Based on the geochemical, seismic, logging and drilling data, the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics, the tight oil enrichment model and its major controlling factors. First, the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation, with the development of nose structure around sag and the broad and continuous distribution of sand bodies. The reservoirs are tight on the whole. Second, the configuration of multiple elements, such as high-quality source rocks, reservoir rocks, fault, overpressure and structure, controls the tight oil enrichment in the Fuyu reservoirs. The source-reservoir combination controls the tight oil distribution pattern. The pressure difference between source and reservoir drives the charging of tight oil. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline area for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, accumulation dynamics and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated is migrated vertically or laterally to and accumulates in the adjacent reservoir rocks; (2) transport of hydrocarbon through faults between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downward through faults to the sandbodies that are separated from the source rocks; and (3) migration of hydrocarbon through faults and sandbodies between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks, and then migrates laterally through sandbodies. Fourth, the differences in oil source conditions, charging drive, fault distribution, sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs. Comprehensive analysis suggests that the Fuyu reservoir in the Qijia–Gulong Sag has good conditions for tight oil enrichment and has been less explored, and it is an important new zone for tight oil exploration in the future.