Reservoir Fluid Research Articles

WITHDRAWN: Comparative Analysis of Asphaltene Deposition Methods : Stability indices, Stability plots, and Equation of state

Asphaltene deposition is one of the major problems that hinder hydrocarbon production. It can occur anywhere between the reservoir and the surface. Therefore, it is imperative that there be a procedure for minimizing the deposition of asphaltene in the production flow lines. There are several screening criteria that can be considered to determine the asphaltene deposition. This research will conduct a comprehensive study on different methodologies to determine the stability of asphaltene: the first category is the stability criteria using indices such as: the colloidal instability index (CII), the colloidal stability index (CSI), the stability index (SI), and the asphaltene stability predicting model (ANJIS). These four methods are used to predict the stability of asphaltene using SARA analysis. The fifth one is called modified CII which uses the compositions analysis of reservoir fluids, instead of SARA analysis, to determine the stability of asphaltene. The second method uses SARA Analysis to predict the stability via plots such as: Stankiewics plot (SP), De Boer plot, Sepulveda stability criterion (SCP). The third method is using compositional analysis of reservoir fluids and the equation of state model to predict the asphaltene onset pressure (AOP). In the last method Soave Redlich Kwong (SRK) equation of state model was used to predict asphaltene precipitations.In this work, a dataset of 166 was created which includes reservoir information, depth, compositional analysis, and SARA analysis. These data are used to study the potential of asphaltene deposition at the reservoir level. It was found that the stability criteria using indices and plots shows discrepancy in the results. The only two methods that show all the datasets are stable are the modified CII and the EOS model. As far as predicting asphaltene stability is concerned, the EOS method, based on compositional analysis and the thermodynamic model, appears to be the most reliable and trustworthy method. The other methods presented are observational rather than thermodynamic. Using these criteria is intended as a quick and fast estimate of the stability potential of asphaltene, not for planning or management of asphaltene deposition issues.

CO2 Injectivity Test Proves Concept of CCUS Field Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.

Copper sulfide deposition and remobilisation triggered by non-magmatic fluid incursion in the single-intrusion Tongchang porphyry system, SE China

Porphyry ore deposits are a major source of base and precious metals. Likewise, they bear important fingerprints for understanding magmatic / hydrothermal processes in the convergent margin. For many decades, the sources of non-magmatic fluid and its role in sulfide mineralization in the porphyry hydrothermal systems have been equivocal. The Tongchang porphyry deposit, which is a single intrusive system with a well-established fluid history, is investigated to reconstruct its hydrothermal process that contributed to the ore formation. In-situ oxygen and strontium isotopes in hydrothermal quartz and anhydrite revealed a coexistence of magmatic and non-magmatic fluid reservoirs. The granodiorite—derived magmatic fluid and external groundwater were spatially separated by a hydrologically impermeable shell formed by retrograde mineral deposition (mainly quartz). The location of the impermeable shell coincided with a brittle-ductile transition (BDT) interface established in the host phyllite in response to latent heating by the cooling magmas. It is inferred that the ductile phyllite beneath the impermeable shell may have entrained some amounts of groundwater and remnant metamorphic fluid. The early fluid stage was dominated by the magmatic fluids, forming disseminated chalcopyrite and barren quartz veins in the potassic-altered ductile granodiorite at high temperatures (> 500 °C). The next stage (early-intermediate) was also driven by the circulation of the magmatic fluids, but in a largely brittle zone formed in-between the impermeable shell and the retreated BDT interface (similar to the so-called “carapace” in the orthomagmatic models). In this stage the formation of pyrite and chalcopyrite veins together with chloritic alteration at temperatures of 400–350 °C occurred. The late-intermediate stage was marked by incursion of the trapped non-magmatic fluids due to rupturing of the enlarged carapace. Mixing of the non-magmatic fluids and the magmatic fluids led to deposition of a major phase of vein-type Cu sulfide at temperatures of 350–300 °C. The late fluid stage was characterized by breaching of the impermeable shell in response to volumetric contraction of the fluid system, leading to excessive infiltration of groundwater and ore remobilization. Based on the Tongchang model, six generic fluid models are proposed for porphyry ore deposits that differ in availability of non-magmatic components as well as intrusive histories. The models can account for variabilities in ore and alteration styles found in porphyry ore deposits globally.

Investigating the Influencing Factors of Imbibition of Fracturing Fluids in Tight Reservoirs

Tight reservoirs are the focus of unconventional oil and gas resource development, but most tight reservoirs exhibit complex pore structures, strong non-homogeneity, and limited water drive development. Fracturing fluid imbibition is a critically important way to improve the recovery of tight reservoirs. In this paper, an NMR experimental device was used to conduct imbibition experiments in tight reservoirs, and the relationship between temperature, pressure, matrix permeability, and imbibition recovery was investigated. Based on the fracturing fluid imbibition recovery curve, the imbibition process is divided into the fast imbibition stage, slow imbibition stage, and imbibition equilibrium. In addition, based on the pore structure division, the recovery changes of each pore under different experimental conditions were quantitatively analyzed. The results indicate that the highest imbibition recovery is achieved at an experimental pressure of 5 MPa within the range of 0 MPa to 15 MPa. Increasing the experimental pressure can increase the imbibition rate but will not increase imbibition recovery. Within the investigated range in this paper, fracturing fluid imbibition increases with rising temperature and matrix permeability. Moreover, the recovery of each pore gradually increases with the experimental pressure ranging from 0 MPa to 5 MPa. The recovery of each pore is positively correlated with matrix permeability and temperature. During the experiment, micropores contributed the most to the recovery, while macropores contributed the least. The study in this paper guides the efficient development of tight reservoirs.

A close look at the H-C phase Diagram and Hydrocarbon Reservoir Classification and Behavior

H-C phase diagram of reservoir fluids is an important tool used in explaining reservoir fluids behavior during the life period of any reservoir. In this paper, detailed analysis of certain terms of the Pressure–Temperature Diagram (P-T diagram) are presented and discussed. Some of these terms are redefined since the already existing definitions does not fit all cases and conditions of reservoir pressure and temperature, and hence, new definitions are given to such terms so as to make them fit all possible conditions that might exist in the reservoir. Special attention was given to explain and analyze the phase behavior inside the phase envelope (two phase region) of the P-T diagram. Among such terms for example, new definitions and analysis are given to the quality lines to give them much more interest and importance in the P-T diagram as they should be given than just representing the percentages of both liquid and gas phases. The new given definition will open new interpretations and add more interesting and valuable importance to the quality lines. Another new definition is given herein to the Cricondenbar Pressure to make it fit all possible conditions on the P-T diagram since the existing definition does not fit all pressure and temperature conditions. This paper also include some explanations regarding the retrograde gas condensation process and region on the P-T diagram. Finally, the herein mentioned factors and definitions will add more important and wider interpretations and applications for the P-T Diagram for a better understanding of H-C reservoirs. Such interpretations might be applied, also to the fluid flow control inside the reservoir and in the choosing of the best EOR method to apply whenever and wherever it is necessary.

The bitumen development effect on the pore structure and electrical resistivity of carbonate reservoirs in the Sinian Dengying Formation

Abstract In the Sichuan Basin, bitumen widely distributes in the carbonate reservoir, and the bitumen occurrence morphology affects the pore structure and petrophysics. Two types of bitumen, boundary-filled and centre-filled, were reconstructed using a pore morphology-based method based on dolomite carbonate digital cores from X-ray computerized tomography. The pore structures of the reconstructed bitumen-filled digital core models were determined using an extracted pore network model. The finite element method simulated the electrical resistivity of the digital core model. The investigation showed that (i) boundary-developed bitumen increases the pore size whereas centre-developed bitumen decreases the pore size, and bitumen development increases the shape factor while reducing the coordination number; (ii) for electrical resistivity, boundary-filled bitumen increases the porosity exponent with increasing pore size, whereas centre-filled bitumen decreases the porosity exponent. Bitumen development caused a negative correlation between the porosity exponent and pore shape factor, a logarithmic increase between the porosity exponent and coordination number, and a power increase between the porosity exponent and porosity. Subsequently, a new porosity exponent model related to porosity was proposed based on the curve-fitting method. This new porosity exponent combines the Archie equations to calculate the saturation of the carbonate reservoir in the Sinian Dengying Formation in the Penglai gas area on the northern slope of the central Sichuan paleo-uplift, which fits the sealed core plug saturation well and provides the basis for further reservoir evaluation and fluid identification in the Penglai gas area.

Study on the influence of perforation parameters on hydraulic fracture initiation and propagation based on CDEM

Perforation hydraulic fracturing plays a crucial role in the development of oil and gas reservoirs, and perforation layout can significantly affect the initiation and propagation of complex reservoir rock fractures. In this paper, we used a mixed finite-discrete element method with an explicit iterative scheme called the continuous–discontinuous element method (CDEM) to study the process of hydraulic fracture propagation through perforation. The coupling effects of fluid flow and reservoir mechanics are fully considered, and the accuracy of the model in simulating the directional propagation of perforation hydraulic fractures is validated by comparison with physical experimental results. We also discussed in detail the impact of perforation pattern, density, depth, and aperture on crack initiation, propagation, and complexity, and used the new index of fracture degree to quantitatively evaluate the fracturing effects under the influence of multiple perforation layout parameters. The results indicate that: (i) hydraulic fractures near the wellbore compete for initiation, and the length distribution of cracks is uneven and intricate; (ii) linear perforation patterns produce the maximum initiation pressure, which is negatively correlated with the perforation density and positively correlated with the perforation depth and aperture; (iii) the fracture degree is mainly affected by perforation density and depth, and is less affected by aperture. Perforation can effectively control the fracture morphology and initiation pressure, and has a substantial influence on the crack propagation layout near the wellbore. This study provides a basis for the rational selection and optimization of perforation parameters, which can effectively improve the fracturing effects of tight oil and gas reservoirs.

Hybrid parameters for fluid identification using an enhanced quantum neural network in a tight reservoir

This paper proposes a fluid classifier for a tight reservoir using a quantum neural network (QNN). It is difficult to identify the fluid in tight reservoirs, and the manual interpretation of logging data, which is an important means to identify the fluid properties, has the disadvantages of a low recognition rate and non-intelligence, and an intelligent algorithm can better identify the fluid. For tight reservoirs, the logging response characteristics of different fluid properties and the sensitivity and relevance of well log parameter and rock physics parameters to fluid identification are analyzed, and different sets of input parameters for fluid identification are constructed. On the basis of quantum neural networks, a new method for combining sample quantum state descriptions, sensitivity analysis of input parameters, and wavelet activation functions for optimization is proposed. The results of identifying the dry layer, gas layer, and gas–water co-layer in the tight reservoir in the Sichuan Basin of China show that different input parameters and activation functions affect recognition performance. The proposed quantum neural network based on hybrid parameters and a wavelet activation function has higher fluid identification accuracy than the original quantum neural network model, indicating that this method is effective and warrants promotion and application.

The effect of gas solubility on the selection of cushion gas for underground hydrogen storage in aquifers

Underground hydrogen storage (UHS) is gaining worldwide attention as an efficient solution for energy supply-demand imbalance. However, deploying UHS at full scale encounters several challenges. One of the primary challenges is selecting a suitable cushion gas to optimize hydrogen storage and withdrawal efficiency. In the existing literature cushion gas dissolution in the resident reservoir fluid is not considered as one of the technical selection criteria and we aim to show in this paper that it is critically important as it affects hydrogen recovery, pressure maintenance and hydrogen purity. With a focus on hydrogen storage in aquifers, we investigated cushion gas solubility in water. Three potential cushion gases—carbon dioxide, methane, and nitrogen—were assessed through large-scale compositional simulations using a conceptual aquifer model, considering temperature and pressure conditions corresponding to the reservoir depth. Gas solubility analysis involved examining changes in reservoir pressure, water production, injected cushion gas volume, and gas saturation changes during the cyclic process. Two distinct scenarios, with and without gas solubility, were considered to understand the effect of solubility on produced hydrogen purity and efficiency. Results indicate that increasing cushion gas solubility decreases final hydrogen recovery. For the case of carbon dioxide, due to its high solubility in the reservoir water, hydrogen purity is reduced to 30 % and hydrogen recovery factor falls by 18 % compared to using methane and nitrogen. Despite this, carbon dioxide dissolution can favorably reduce cumulative water production and mitigate severe reservoir pressure drops during production. Therefore, the dissolution phenomenon should be a key consideration in the screening of cushion gases and subsequently in the design and operation of UHS. Understanding the relationship between cushion gas solubility and hydrogen production efficiency contributes to enhancing the overall performance, and the long-term success of UHS projects.

Prediction of wellbore sand production potential from analysis of petrophysical data coupled with field stress: a case study from the Shah-Deniz gas field (Caspian Sea Basin)

Identifying the optimal azimuth and inclination for wellbore drilling in sandy formations can be considered a valuable aid in reducing sand production risks, lost time, and decreasing drilling costs in the petroleum industry. Therefore, a numerical systematic approach was provided to predict sand production in wellbore SDX-5, drilled in a deep-water sandstone reservoir in the Shah-Deniz gas field (South Caspian Basin), which has never been done previously. Additionally, this systematic approach uses geomechanical and geodynamical criteria, along with petrophysical information (density and sonic log) and tectonic characteristics of the study area, which are influenced by the active tectonic stresses of the Apsheron-Balkhan zone. The subsurface data sources employed are more eco-friendly, available, and continuous than experimental tests. The computations conducted achieved azimuth, inclination, polar, and depth profile plots for the Lower Balakhany Formation. The calculations reveal that the optimum azimuth for the wellbore drilling trajectories is parallel to SHmax and oblique drilling to near horizontal is the result of optimum inclination. Polar plots showed optimum azimuth, inclination, and effect of wellbore trajectory on critical collapse pressure and collapse drawdown pressure with pressure values simultaneously, which identify safer alternatives for achieving higher petroleum production rates without sanding. Depth profile plots provide a simultaneous overview of the values of critical collapse pressure, critical sanding pressure for instantaneous drawdown, and optimum wellbore production pressure during drilling and production operations. Moreover, optimum reservoir fluid production (maximum discharge) rates can be identified and imposed as upper limits to prevent sand production.

The Impact of Electromagnetic Waves Propagation to the Dielectric Nanoparticles on Crude Oil Interfacial Tension Reduction for Oil Recovery: A Review

The presence of interfacial tension (IFT) force between crude oil and other fluids in reservoirs is one of the critical parameters that restrict the effective mobility of the oil and is continuously entrapped in reservoir pores. Reducing binding forces between oil and such fluids is one of the methods employed to improve oil productivity known as enhanced oil recovery (EOR). Various nanoparticles (NPs) have been utilized to reduce IFT. However, NPs encountered a challenge in terms of successful operation under a high temperature. Consequently, the NPs tend to segregate at the oil/ water interface which diminishes the IFT influences and more oil continuously entrapped. Recently, an innovative approach to enhance oil mobility was proposed by activating the charges of the NPs via electromagnetic (EM) wave propagation. Few analyses were reported using dielectric NPs with reasonable reductions to IFT. The dielectric properties of NPs are essential attributes corresponding to EM waves. During the EM wave exposure, the extra disruptions were generated at the fluid/oil interface that function as activating agents for the NPs resulting in the additional reduction for IFT. The present study provides a comprehensive review of the few results available, challenges that confronted the success of this novel approach, and admirable recommendations to improve the process in the future.

The effect of lunar declination on CO<sub>2 </sub>degassing from central Italian Apennines

<p>The periodical degassing from CO<sub>2</sub> over-pressured reservoirs may have serious consequences for the environment making urgent understanding the processes and forecasting the frequency. Prediction though needs methods that depends from temporal and spatial properties of hydro-chemical and physical reservoir characteristics that unfortunately are often lacking. We have analyzed surface emissions of CO<sub>2</sub> attributed to over-pressured CO<sub>2</sub>-rich reservoirs in the Central Italian Apennines a zone characterized by significant periodical CO<sub>2</sub> degassing. Here aquifers are hosted in Mesozoic limestone with high pCO<sub>2</sub> groundwater and travertine deposits. We analyzed a 10-year temporal series and found that in the Apennines CO<sub>2</sub> flux and aquifer fluid composition are correlated with the lunar tides. In particular, our study reveals that low CO<sub>2</sub> flux corresponds with low lunar tidal potential values. We found a similar trend for dissolved calcium and water alkalinity, while pH values display a linear correlation with tidal cycles. The forces associated with tidal potentials are not capable of fracturing rock. However, they can, under certain conditions, drive the flow of fluids in over-pressured reservoirs, triggering sub-surface fluid movements that in turn modify the water�Crock reactivity. In the central Apennines, we show that these movements result in increased dolomite dissolution and an eventual return to calcite equilibrium. In this case, dolomite dissolution breaks the rock releasing calcium into ground water, which leads to calcite equilibrium and in turn to the formation of significant quantities of travertine and the concomitant release of CO<sub>2</sub> in the atmosphere.</p>

Autonomous navigation and control of magnetic microcarriers using potential field algorithm and adaptive non-linear PID.

Microparticles are increasingly employed as drug carriers inside the human body. To avoid collision with environment, they reach their destination following a predefined trajectory. However, due to the various disturbances, tracking control of microparticles is still a challenge. In this work, we propose to use an Adaptive Nonlinear PID (A-NPID) controller for trajectory tracking of microparticles. A-NPID allows the gains to be continuously adjusted to satisfy the performance requirements at different operating conditions. An in-vitro study is conducted to verify the proposed controller where a microparticle of 100 m diameter is put to navigate through an open fluidic reservoir with virtual obstacles. Firstly, a collision-free trajectory is generated using a path-planning algorithm. Secondly, the microparticle dynamic model, when moving under the influence of external forces, is derived, and employed to design the A-NPID control law. The proposed controller successfully allowed the particle to navigate autonomously following the reference collision-free trajectory in presence of varying environmental conditions. Moreover, the particle could reach its targeted position with a minimal steady-state error of 4 m. A degradation in the performance was observed when only a PID controller was used in the absence of adaptive terms. The results have been verified by simulation and experimentally.

Numerical simulation of enhanced throughput of surfactant in Lamadian oilfield

Based on the actual data of Lamadian oilfield in terms of geological structure, reservoir fluid physical properties and production dynamics, a numerical simulation geological model of CMG STARS chemical flooding module is established, which is consistent with the static and dynamic characteristics of the oil reservoir. In order to study the effect of enhanced throughput of surfactants, based on the mechanism of enhanced throughput of surfactants, the numerical model was established by defining parameters such as oil-water interfacial tension at different concentrations, residual oil saturation, oil-water relative permeability curve, capillary pressure, isotonic point change and surfactant diffusion coefficient in the formation, etc. The numerical simulation of surfactant enhanced throughput was carried out to optimize the surfactant enhanced throughput parameters in Lamadian oilfield, and the sensitivity sequence of each injection and production parameter to the surfactant enhanced throughput and oil was determined. The final recommended injection and production parameters are surfactant injection amount (10000m3), injection concentration (0.5%) and brazing time (2d). It is predicted that the cumulative oil increase can reach 1310m3, the initial daily fluid production is controlled at 80m3/d, the daily oil production can be increased by 10m3/d, and the water cut can be reduced by 10%.

Construction of Numerical PVT-Models for the Bulla-Daniz Gas-Condensate Field Based on Laboratory Experiments on Reservoir Fluid Samples

PVT analysis is important for field-wide optimization and development. This is because we must understand the fluid's overall behavior from the reservoir to the production and processing facilities, and ultimately to the refinery. Modern computer software that uses equation of state (EOS) models to simulate experiments and illustrate fluid phase characteristics has contributed to its growth as a distinct field of study. To find the operating parameters that will maximize the surface liquid content and prolong the production plateau duration at the lowest feasible cost, PVT simulations are run. These simulations employ laboratory-derived data to fine-tune the EOS models, with the outcomes being integrated into reservoir simulation and research. The quality of the data is crucial to getting a good match between EOS and laboratory data, and for retrograde gas condensates, this can be particularly difficult because of their complex phase behavior. When utilized in reservoir simulations, an inadequate match leads to computational mistakes and unrepresentative findings, endangering the reservoir management decisions that depend on it.

Phase characteristics modeling of reservoir gas-condensate mixture of Tegermen group of fields

Taking into account the forthcoming concept, it is proposed to develop Tegermen group of fields with construction of onshore systems for collection, treatment and transportation of natural gas in order to supply the extracted products to the gas treatment point (Samantepe gas treatment unit-2) in a single-phase state. Natural hydrocarbon systems consist of a large number of components, and these are not only hydrocarbons of the paraffin series, but also hydrocarbons belonging to other groups. The phase state of a hydrocarbon mixture depends on its composition, as well as on the properties of individual components. Construction in a wide range of temperature and pressure values of phase diagrams of reservoir fluids with low condensate factor allows to determine with high accuracy the parameters of the beginning of condensate precipitation (dew point) in the system of gas gathering and transportation to supply the produced products of Tegermen group of fields.

Reservoir geophysical monitoring supported by artificial general intelligence and Q-Learning for oil production optimization

<p>Artificial general intelligence (AGI), or strong AI, aims to replicate human-like cognitive abilities across diverse tasks and domains, demonstrating adaptability and learning like human intelligence. In contrast, weak AI refers to systems designed for specific tasks, lacking the broad cognitive flexibility of AGI. This paper introduces a novel approach to optimize oil production by integrating fundamental principles of AGI with geophysical data inversion and continuous monitoring techniques. Specifically, the study explored how AGI-inspired algorithms, combined with established reinforcement learning (RL) techniques, can enhance borehole electric/electromagnetic monitoring and reservoir fluid mapping technology. This integration aims to mitigate the risk of unwanted water invasion in production wells while optimizing oil extraction. The proposed methodology leverages real-time geophysical data analysis and automated regulation of oil production. The paper begins by outlining the key features of AGI and RL, and then discusses their application in electric/electromagnetic monitoring to define optimal production policies. The effectiveness of this approach was verified through synthetic tests, showing significant improvements in production efficiency, resource recovery, and environmental impact reduction.</p>

Effect of Matrix Characteristic and the Pore‐Throat Limit for Water Imbibition in Early Jurassic Tight Sandstone Reservoir of the Tuha Basin

Spontaneous imbibition (SI) is a fundamental mechanism for improving the production efficiency of tight sandstone reservoirs. Matrix characteristic plays important roles in the SI process, but how these factors affect SI and the limit pore‐throat size of effective driving force in the tight sandstone of the Tuha Basin has not been firmly established. Thus, a series of experiments (FE‐SEM, QEMSCAN, XRD, CT, and SI) of four tight sandstone core samples were conducted under laboratory conditions in the Tuha Basin. The results show that quartz and plagioclase feldspar are the main detrital minerals, while illite and illite/smectite (I/S) are the predominant clay minerals of those sandstone samples, and they have a micro‐nano (<2 μm) to meso‐macro (>10 μm) pores, but the micro‐nano pore performance disconnected, and during SI process, fluid enters small and meso‐macro‐size pores simultaneously. However, small pores play a dominant role in the initial stage (with steep imbibition slopes), while meso‐macro pores predominate in the second stage (with shallow imbibition slopes), and the limit pore‐throat value of the tight sandstone is around 9.1 μm in the Tuha Basin, beyond which the SI will be weakened. Though the mineral composition and its wettability will be changed with fluid environment (especially for clay minerals), the small pores (formed by clay minerals) always play a dominant role than meso‐macro‐size pores (mainly formed by quartz and plagioclase feldspar) in SI process. These observations can improve our understanding of fluid–reservoir interaction in the Tuha Basin’s tight sandstone reservoir and provide guidance for improving oil and gas recovery.

Prospects for mathematical modeling in mining system development: accounting for global oscillations and seismic waves

The article discusses the potential of mathematical modeling in understanding the impact of vibrations and seismic waves, aiming at enhancing the sustainability of systems within the mining industry. It explores the dynamic response of a tall, elastic structure with a uniform cross-section and a fixed cylindrical fluid reservoir, subject to various complex boundary conditions. The study delves into the vibrational behavior of the structure when exposed to seismic and harmonic forces, calculating frequency, vibration periods, and deriving formulas for stress, tension, deformation, bending moments, and shear forces in different parts of the structure through both theoretical and experimental approaches. Additionally, the article derives the differential equation for the free oscillation of a tall hydraulic structure in pure bending with an incorporated mass load under appropriate boundary conditions, identifying specific vibration frequencies and periods. The forced vibration scenario is also examined, focusing on the structure's foundation movement due to external harmonic forces. Numerical computation technology is utilized to analyze the change laws of principal quantities that describe both free and forced vibrational movements of the hydraulic structure, showcasing the applicability of these models in predicting and mitigating the effects of seismic activities on mining infrastructure.

Lessons Learned in Interfacial Tension Prediction Using a Mixture of Sulfonate- and Ethoxylate-based Surfactants in a Waxy Oil-brine System

The chemical-enhanced oil recovery (CEOR) method is applied to change reservoir rock or fluid characteristics by injecting alkaline, surfactant, and polymer or a combination of two or three of the compounds. Surfactant flooding improves oil recovery by reducing the interfacial tension between oil and water. Selecting reservoir surfactants, especially microemulsions, requires careful screening. This study predicted waxy oil system interfacial tension using surfactant mixtures at below- and above-optimum salinity. To predict the interfacial tension, microemulsion types, HLB, ideal salinity, and HLD were used. The study predicted oil-surfactant-water interfacial tension using SAE, FEO, and their mixtures. We improved the Huh equation by adding a fitting parameter, β, to accommodate the transition from type III to type II microemulsions as salinity increases. With increasing salinity, anionic surfactant’s hydrophilic-hydrophobic interactions change, affecting the values and surfactant layer thickness. This study improved hydrophilic-lipophilic deviation (HLDN) by establishing a fixed interval for nonionic surfactants. Van der Waals attraction, values and interface surfactant layer thickness are connected, reflecting the fact that lower values reduce interfacial tension better. This study also found that surfactant packing at the oil-water interface increases the order of the oil-solution ratio and the microemulsion values with polarity.