Reservoir Fluid Research Articles

Short-term changes in the trabecular iris angle and anterior chamber during wear of scleral lenses with different diameters

ABSTRACT Clinical relevance Scleral lens (SL) compression on the conjunctiva/episclera during wear may alter adjacent structures related to aqueous humour drainage. Background The aim of this work was to assess short-term changes in the four quadrants of trabecular iris angle (TIA) and anterior chamber parameters during SL wear, using anterior segment optical coherence tomography (AS-OCT). Methods Prospective study was conducted involving 16 healthy subjects with a mean age of 28 ± 5 years. Two SL of diameter 15.80 mm (L1) and 16.80 mm (L2) with the same parameters were used for 2 hours in different days. The central fluid reservoir (FR), the TIA in superior, inferior, nasal, temporal quadrants, and anterior chamber parameters; anterior chamber depth (ACD), anterior chamber width (ACW), anterior chamber area (ACAr) and anterior chamber volume (ACV) were measured with AS-OCT. These measurements were performed immediately after SL application (0 h), one hour (1 h) and two hours (2 h) of SL wear. Results TIA decreases significantly in the superior quadrant at 2 hours of L2 wear (−5.19 ± 7.79º) (p = 0.04). In this sector, differences were also observed between the changes induced by both lenses during the 2 hours of wear (p = 0.04) and between first and second hours of wear (p = 0.04). ACD was significantly lower with L1 (−0.09 ± 0.14 mm) relative to L2 (0.00 ± 0.06 mm) between immediately after the application and 2 hours of wear (p = 0.02). A significant reduction in ACAr at 1 hour (−0.65 ± 0.75 mm2) (p = 0.01) and 2 hours of wear (−0.81 ± 1.15 mm2) (p = 0.04), as well as in ACW at 2 hours (−0.11 ± 0.14 mm) (p = 0.02) compared to immediately after application of L1 was found. Conclusion Small changes in TIA and anterior chamber occur during two hours of SL wear, but these changes are of limited clinical relevance in healthy subjects.

Influence of reservoir water saturation on coalbed methane development: Based on multi-field coupling numerical simulation

Water in coal reservoirs serves as both the driving force of reservoir fluid and the resistance to coalbed methane (CBM) migration. However, the impact and control mechanism of water saturation on CBM development in the field have not been revealed yet. The evolution of reservoir dynamics and gas production rate under various initial water saturation conditions is simulated based on the COMSOL multiphysics numerical simulation software. The simulation results show that the reduction of initial water saturation can significantly enhance the effective permeability of the reservoir gas phase, which can be increased by up to 4764%. This increases the rate of gas production, which is the main mechanism for controlling production by water saturation in the reservoir. For high water saturation reservoirs, the positive effect of inter-well interference should be reasonably utilized, and high well network density should be used to rapidly increase gas-effective permeability. For low water saturation reservoirs, the negative effect of inter-well interference should be avoided, and low well network density should be used to increase the control of single well reserves.

Активизация пластовой микрофлоры для повышения нефтеотдачи

Constant optimization of technological processes of oil production is one of the integral parts of rational subsurface use. The study and implementation of new developments and technologies in the oil production process is primarily due to the economic effect. Methods of increasing oil recovery are of particular interest in the practical implementation of innovative technologies in the oil and gas industry. To date, a huge number of technologies have been developed and tested in field conditions aimed at preserving and increasing the volume of produced products, the classification of which is very diverse. The primary criteria for choosing a method or combination of methods of influencing a productive reservoir in order to increase oil recovery are the geological conditions of the productive horizon, as well as the composition and physico-chemical properties of reservoir fluids. Currently, of all the many methods of increasing oil recovery, the microbiological method is the least studied, as a result of which it is extremely rarely used in enterprises. The relevance of research on the effects of microorganisms on the reservoir rock is beyond doubt. The possibility of widespread application of oil recovery enhancement technology based on bacterial life processes is interesting both from the point of view of environmental safety and economic efficiency. One of the microbiological methods of increasing oil recovery is the activation of the existing reservoir microflora by feeding a nutrient medium into the reservoir. In the course of their vital activity, some types of bacteria are capable of destroying clay rocks, which entails changes in the filtration and capacitance properties of the reservoir rock and, as a result, the volume of products produced increases significantly. The advantage of this method is the absence of the need for forced “contamination” of the reservoir formation, since the necessary bacteria are already in it.

Methodological approaches to assessing the invasion of process fluids into the core pore space

Background. The reliability of the lithological and petrophysical studies is largely determined by the quality of the core material. The invasion of drilling mud filtrate into the core will primarily affect the measurements of the fluid type, residual oil and water saturation, porosity, permeability, geochemical properties and wettability of the rock. Evaluating the suitability of the core material for laboratory studies is one of the main tasks in the study of low-invasion core. Objective. To determine the most informative methods of penetration of process fluids into the pore space of the rock to assess the suitability of the core for laboratory studies. Materials and methods. The paper uses the methods of lithological and petrophysical research of core and reservoir fluids. Results. The application of the used research methods is analyzed. The advantages and limitations of each of the presented methods are determined. Conclusions. The assessment of the degree of mud filtrate invasion into the core determines the suitability of the core material for further petrophysical research.

Fluorescence visualization dynamics of carbonated water injection processes in homogeneous glass micromodels

Understanding the flow behavior of oil–water phases in porous media is crucial for revealing the kinetic mechanisms underlying oil–water movement. In this study, we designed and constructed a fluorescence visualization experimental platform for carbonated water injection (CWI). We evaluated the effects of nine distinct injection rates on oil production and CO2 sequestration capabilities using three types of homogeneous porous structure micromodels. The microscale oil–water seepage behavior at the pore scale was also explored. The experimental results indicate that optimally increasing the injection rate can improve displacement efficiency, whereas excessively high rates may lead to viscous and capillary fingering. The geometry of the micromodels, particularly the hexagonal matrix, demonstrates potential advantages in enhancing oil displacement due to its uniform flow paths. The capillary number (Ca) significantly influences oil droplet capture behavior within micromodels. For instance, micromodel A captures the largest ganglion area at low Ca values, with a noticeable reduction in average ganglion area as Ca increases. Conversely, micromodels B and C exhibit similar trends in ganglion size variation at high Ca values, suggesting a more uniform impact of pore structure on oil droplet capture behavior. At elevated Ca values, capillary forces exert a more uniform and controlled effect on oil droplet capture and release, minimizing size variability. Additionally, the injection rate plays a critical role in CO2 sequestration, with higher rates promoting convective mixing between CO2 and reservoir fluids, thereby enhancing dissolution and storage efficiency. The complexity of the pore structure, characterized by the presence of micropores and macropores, affects the dissolution kinetics and mobility of CO2, influencing sequestration efficiency. These experimental findings provide valuable insights into the dynamics of oil–water motion and the potential for enhanced oil recovery (EOR) and CO2 storage, offering essential guidance for optimizing CWI strategies in the petroleum industry.

Enhancing Oil Recovery in Eagle Ford Shale: A Multiscale Simulation Study of Surfactant Huff ’n’ Puff Methodology

In this paper, we present a simulation case study of a surfactant huff ’n’ puff pilot in the black oil window of the Eagle Ford (EF) Shale. The target horizontal well, which had been depleted for nearly 8 years, underwent stimulation via a surfactant huff ’n’ puff treatment. The surfactant was selected through laboratory screening using reservoir rock and fluid samples. After a 17-hour injection and a 1-month shut-in period, the well’s production increased fivefold from the baseline oil rate, sustaining incremental oil production for at least 2 years. The surfactant enhances oil recovery by altering rock wettability toward a more water-wet state and moderating oil/water interfacial tension (IFT). This process is modeled by surfactant adsorption in the simulator, indicating the degree of dynamic changes in relative permeability (krl) and capillary pressure (Pc) curves. We propose a comprehensive workflow comprising three stages: development of core-scale and field-scale models, sequential model calibrations, and multiobjective optimization to integrate laboratory measurements and field data from this pilot into multiscale numerical simulations. By matching oil recoveries from imbibition experiments on the core model and field production histories on the field model, krl and Pc profiles of two extreme states, basic reservoir properties, and additional reservoir properties altered during huff ’n’ puff operations are characterized. The matched core model reproduces a 15.1% incremental oil recovery for surfactant-assisted spontaneous imbibition (SASI) process relative to pure brine imbibition process. The matched reservoir model predicts the surfactant huff ’n’ puff treatment increases the oil production by 21.9% relative to water huff ’n’ puff treatment and by 52.9% relative to primary depletion for a 4-year period. The calibrated reservoir model also serves as a base case for optimizing well operation schedules through the implementation of a multiobjective genetic algorithm. The surfactant injection rate, injection time, and well shut-in time of the base case are varied to achieve higher oil production and reduced surfactant usage. Statistical analysis of eight trade-off cases indicates that optimal well operations, compared with existing practices, frequently involve increased injection rates [16.6–18.9 barrels per minute (bpm)], shorter injection periods (10–11.3 hours), and prolonged shut-indurations (49–65 days). This workflow offers valuable insights into surfactant huff ’n’ puff treatments for unconventional reservoirs, thereby facilitating the optimization of well operations and maximizing tertiary oil recovery.

Research of productivity and interlayer interference mechanism of multilayer co-production in reservoirs with multi-pressure systems

Abstract Due to the differences of physical and fluid properties in vertical oil layers, the interlayer contradictions are prominent and affect the reservoir utilization degree seriously. Therefore, the coordination between reasonable bottom-hole flow pressure and optimal production, as well as the reduction of interlayer interference are the primary concerns during the co-production of multi-layer oil reservoirs. Based on the reservoir engineering and fluid mechanics in porous media theory, this work adopt the comprehensive pressure system and consider the interlayer interference to establish a multi-branch horizontal well productivity model and interlayer interference mathematical model. By analyzing the main controlling factors and interference mechanisms, this article establishes a pattern of interlayer interference, and improves the quantitative characterization interlayer interference theory in multi-layer combined mining. The study has shown that: (1) The interlayer interference is beneficial for balancing the production of different layers and improving development efficiency, it is greatly affected by interlayer heterogeneity; (2) When the number of layers exceeds 2 layers, the interference coefficient increases; With the increase of the layer thickness, the thicker oil layers have higher productivity, and the thickness of layer has a significant effect on the production of low-pressure layer; When the production pressure difference increases, the interlayer interference can be reduced; (3) The interlayer interference mathematical model constructed in this paper has high prediction accuracy and strong practicality, which has theoretical guidance significance for the division of strata in comprehensive adjustment of reservoirs.

Autonomous Inflow Control Devices Help Maximize Life of Wells in Deepwater West Africa

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35418, “Design Execution and Evaluation of Advanced Completions in Deepwater West Africa,” by Piyush Pankaj, SPE, Matthew S. Jackson, and Lokesh, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Deepwater wells offshore West Africa traverse a complicated faulted block with sand bodies that can feature thicknesses of tens of meters. The study described in the complete paper provides insight into designing advanced well completions under various challenging reservoir conditions with autonomous inflow control devices (AICDs) that enable maximizing the producing life of the wells. Introduction The study area for this paper has been a challenging brownfield. Wells have been drilled in difficult deepwater conditions, and the target reservoirs have been lenticular sands with interbedded shale layers. To further complicate production, the sand bodies are poorly consolidated. Openhole wells with standalone screen and gravel packs have become a common approach to address sand control. Water- and gas-injection programs have been used actively in the field during the past 25 years, which further augments production and reservoir management challenges. Water and gas breakthrough in the infill wells has been a major concern for reservoir management. To address the gas buildup in the near-wellbore region and early water production, AICDs have become a popular feature in the lower well-completion designs in high-angled wells that intersect multiple sand bodies along the lateral completion interval. Two case studies are provided in the complete paper; one is included in this synopsis. Flow-Control Technology Although technology that empowers the ability to control the flow of unwanted fluids from zones in the well has been in use since the 1990s, flow-control technology has rapidly evolved, with advancement fueled by the need for long, complex well designs. The two broad categories of these approaches include active and passive flow control. The decision to use inflow-control technologies can be driven by the following economic values: - Balance drawdown along the wellbore - Increase recovery factor and reserves - Improve well cleanup - Reduces risk of erosion or hot-spotting of sandface completion Choice of Inflow Control for West Africa Field of Study Fluidic-diode AICDs were chosen because of their applicability to encountered fluid properties and reservoir conditions and their robustness of design in providing reliable long-term solutions. The reliability is prolonged in such AICDs because they work without any moving parts. Upon changes in viscosity, density, and rate, the fluid flow path will vary to gain the required control of flow rates. This AICD design, with its special geometry, alters the flow path or pattern for preferential fluid restriction. Operational Execution Ultimately, the AICDs were deployed on an inner string. This allowed the standard wire-wrapped screens and gravel pack to function as the traditional sand-control mechanism, while the inner string, deployed inside the lower completion, provides resistance to flow from unwanted gas production.

Tectonic–Hydrothermal Processes and their Relationship with the Petroleum Potential of the Bazhenov-Abalak Complex of Western Siberia

Abstract —The main types of reservoir rocks have been identified within the Bazhenov-Abalak complex. To assess the geological resources of hydrocarbons, it is proposed to formally divide the entire set of lithological rock types comprising the Bazhenov-Abalak complex into two main varieties: fluid seals and reservoirs. We argue that it is possibile to distinguish between potentially productive and productive rocks, represented by siliceous and carbonate varieties, according to logging data. A possible mechanism for the formation of reservoir rocks within the Bazhenov-Abalak complex as a result of the tectonic-hydrothermal impact on these deposits has been reconstructed. An original methodology for identifying perspective zones of various categories of hydrocarbon accumulation in the Bazhenov-Abalak complex through integrating seismic data and tectonophysical modeling carried out on their basis has been proposed. For example, an assessment of the predicted geological resources of hydrocarbons contained in the Bazhenov-Abalak complex within the limits of 3D seismic exploration of the Yem-Yegovskaya area has been carried out. The necessity of assessing the prospects for oil content and calculating the predicted geological resources of hydrocarbons in the whole Bazhenov-Abalak complex, and not only in the Bazhenov Formation, is substantiated, based on a single mechanism of formation of reservoir rocks of tectonic-hydrothermal origin in them.

Coupled Modeling of Computational Fluid Dynamics and Granular Mechanics of Sand Production in Multiple Fluid Flow

Summary Sand production is a significant issue in oil and gas fields with poorly consolidated formations, often involving the multiphase flow of reservoir fluids and solid particles. The multiscale mechanisms of sand production, particularly fluid flow and particle movement, remain poorly understood. This study investigates these mechanisms using a coupled computational fluid dynamics and discrete element method (CFD-DEM) modeling approach. Single and multiple fluid flows of water and heavy oil were simulated with increasing fluid injection velocities, leading to different sand production patterns. The simulation results were compared with experimental results from a large cylindrical specimen of weak artificial sandstone under similar loading conditions. The multiphase conditions created various localized flow and deformation patterns that influenced both fluid and solid production, resulting in shorter transient sand production periods. Microstructures and phenomena such as fingering and water coning were observed, associated with a critical flow rate below which oil displacement was uniform and no water breakthrough occurred. Higher fluid injection velocities and fluid viscosities resulted in greater drag forces, leading to progressive damage zones and explaining the occurrence of single or multiple staged sand production events. The evolution of the microscopic granular structure was visualized under the effect of transient sand production.

Pore Size Classification and Prediction Based on Distribution of Reservoir Fluid Volumes Utilizing Well Logs and Deep Learning Algorithm in a Complex Lithology

Pore size analysis plays a pivotal role in unraveling reservoir behavior and its intricate relationship with confined fluids. Traditional methods for predicting pore size distribution (PSD), relying on drilling cores or thin sections, face limitations associated with depth specificity. In this study, we introduce an innovative framework that leverages nuclear magnetic resonance (NMR) log data, encompassing clay-bound water (CBW), bound volume irreducible (BVI), and free fluid volume (FFV), to determine three PSDs (micropores, mesopores, and macropores). Moreover, we establish a robust pore size classification (PSC) system utilizing ternary plots, derived from the PSDs.Within the three studied wells, NMR log data is exclusive to one well (well-A), while conventional well logs are accessible for all three wells (well-A, well-B, and well-C). This distinction enables PSD predictions for the remaining two wells (B and C). To prognosticate NMR outputs (CBW, BVI, FFV) for these wells, a two-step deep learning (DL) algorithm is implemented. Initially, three feature selection algorithms (f-classif, f-regression, and mutual-info-regression) identify the conventional well logs most correlated to NMR outputs in well-A. The three feature selection algorithms utilize statistical computations. These algorithms are utilized to systematically identify and optimize pertinent input features, thereby augmenting model interpretability and predictive efficacy within intricate data-driven endeavors. So, all three feature selection algorithms introduced the number of 4 logs as the most optimal number of inputs to the DL algorithm with different combinations of logs for each of the three desired outputs. Subsequently, the CUDA Deep Neural Network Long Short-Term Memory algorithm(CUDNNLSTM), belonging to the category of DL algorithms and harnessing the computational power of GPUs, is employed for the prediction of CBW, BVI, and FFV logs. This prediction leverages the optimal logs identified in the preceding step. Estimation of NMR outputs was done first in well-A (80% of data as training and 20% as testing). The correlation coefficient (CC) between the actual and estimated data for the three outputs CBW, BVI and FFV are 95%, 94%, and 97%, respectively, as well as root mean square error (RMSE) was obtained 0.0081, 0.098, and 0.0089, respectively. To assess the effectiveness of the proposed algorithm, we compared it with two traditional methods for log estimation: multiple regression and multi-resolution graph-based clustering methods. The results demonstrate the superior accuracy of our algorithm in comparison to these conventional approaches. This DL-driven approach facilitates PSD prediction grounded in fluid saturation for wells B and C.Ternary plots are then employed for PSCs. Seven distinct PSCs within well-A employing actual NMR logs (CBW, BVI, FFV), in conjunction with an equivalent count within wells B and C utilizing three predicted logs, are harmoniously categorized leading to the identification of seven distinct pore size classification facies (PSCF). this research introduces an advanced approach to pore size classification and prediction, fusing NMR logs with deep learning techniques and extending their application to nearby wells without NMR log. The resulting PSCFs offer valuable insights into generating precise and detailed reservoir 3D models.

АНАЛИЗ ПРОБЛЕМ, ВОЗНИКАЮЩИЕ ПРИ ЭКСПЛУАТАЦИИ ПЕСЧАНЫХ СКВАЖИН

The article considers the causes of the formation of mechanical impurities in deep pump wells and the consequences that it entails for the listed reasons. The impact of solid floating particles in the liquid on the well equipment and the importance of improving the filtration technology of sand- containing liquid to prevent it has been noted. As a method used in the fight against mechanical impurities, the advantages and disadvantages of the filter design, which washes the filter element without lifting the pumping equipment, and the V-shaped wire slotted grilles made of durable stainless steel located in the filter compartment are considered. In practical methods of combating mechanical impurities, the main directions of technology for equipping the bottom areas of wells with filters and the main criteria for combating the negative effects of mechanical impurities are indicated. Based on the special importance of the problem of reducing solid floating particles in the production of a gas-liquid mixture, several methods of insulating sand from impurities used in oil production are considered to protect deep pumping equipment. It is established that solving the problem of increasing the reliability of pumping equipment in the presence of solid float particles in the reservoir fluid requires an integrated approach to the selection of technical means. Analysis of the operability of existing filters in the intake of deep pumps showed that they have low efficiency in the fight against solid floating particles, including the need to periodically raise the pumping equipment for cleaning due to the adhesion of solid floating particles to the surface

Three-Dimensional Coupled Temporal Geomechanical Model for Fault-Reactivation and Surface-Deformation Evaluation during Reservoir Depletion and CO2 Sequestration, Securing Long-Term Reservoir Sustainability

Assessing reservoir subsidence due to depletion involves understanding the geological and geophysical processes that lead to ground subsidence as a result of reservoir fluid extraction. Subsidence is a gradual sinking or settling of the Earth’s surface, and it can occur when hydrocarbons are extracted from underground reservoirs. In this study, a time-integrated 3D coupled geomechanical modeling incorporating the fourth dimension—time—into traditional 3D geomechanical models has been constructed utilizing seismic inversion volumes and a one-dimensional mechanical Earth model (1D MEM). The 3D geomechanical model was calibrated to the 1D MEM results. Geomechanical rock properties were derived from the density and sonic log data that was distributed with conditioning to the seismic inversion volumes obtained from running pre-stack inversion. The standard elastic parameter equations were used to generate estimates of the elastic moduli. These properties are dynamic but have been converted to static values using additional equations used in the 1D MEM study. This included estimating the Unconfined Compressive Strength. In situ stresses were matched using different minimum horizontal principal stress gradients and horizontal principal stress ratios. The match is good except where the weak carbonate faults are close to the wells, where the Shmin magnitudes tend to decrease. The SHmax orientations were assessed from image log data and indicated to be 110° in the reservoir section. A time-integrated 3D coupled simulation was created using the finite-element method (FEM). The effective stresses increase while there is depletion in all directions, especially in the Z direction. The predicted compaction in the reservoir and overburden was 350 mm. Most of the compaction occurs at the reservoir level and dissipates towards the surface (seabed). Furthermore, the case displayed no shear failure that might cause or fault reactivation in the reservoir interval (Kangan–Dalan Formations) located in the simulated area. In this study, we applied an integrated and comprehensive geomechanical approach to evaluate subsidence, fault reactivation and stress alteration, while reservoir depletion was assessed using seismic inversion, well logs, and experiment data. The deformation monitoring of geological reservoirs, whether for gas storage or hazardous gas disposal, is essential due to the economic value of the stored assets and the hazardous nature of the disposed materials. This monitoring is vital for ensuring the sustainability of the reservoir by maintaining operational success and detecting integrity issues.

Characterizing fluid delivery of targeted application devices for weed control

AbstractPrecision weed management in turfgrass and ornamental landscape systems is utilized to offset chemical costs, reduce nontarget plant injury, and control potential herbicide‐resistant weed escapes. Targeted application devices (TADs), sold as wands, dabbers, daubers, sponges, and so forth, are regularly marketed for use in turfgrass and ornamental landscape systems, but TAD use has been limited to nonselective herbicides due to limited information regarding their calibration and use. Five commonly utilized TADs were evaluated to test for variability in fluid output within a given device and between evaluated devices. Fluid output for all evaluated devices ranged 3.2–6.9 kL ha−1 and were higher than spray outputs typical of broadcast applications. High levels of variability were detected within and among specific devices. Variance of output from devices with large fluid reservoirs was driven by reservoir fill level, with more fluid output decreasing linearly as reservoir fill level decreased. Additionally, when airlock was not maintained during application, fluid output was ∼178% greater than when airlock was maintained. Average force, maximum force, contact time, and fluid output following 25 applications were measured from five TAD users. Contact time was highly correlated (R2 = 0.93) to fluid output, with fluid output increasing as contact time increased. Subsequent economic analysis indicated the maximum percentage weed coverage ha−1 at which TAD use is economically equivalent or less than broadcast application is 3%, 8.1%, 4.3%, and 0.1% with iron HEDTA (hydroxyethlethydiaminetriacetate), acetic acid, methiozolin, and glyphosate, respectively. These data indicate the primary sources of TAD output variability are reservoir fluid fill level, reservoir airlock, and duration of application.

Digital core on a chip: Surfactant flooding in low-permeability reservoir

The development of hard-to-recover reserves every year requires ever-more-innovative industrial and laboratory approaches for efficient production of hydrocarbons. Oil industry has recently turned to the use of microfluidic technology to investigate the flow paths and interactions of reservoir fluids under high pressures and temperatures. The present study describes elaboration of a digital core on a chip, i.e. a microfluidic chip with the structure that replicates the void space of a selected reservoir and is designed based on the computed tomography images of core samples. Similarity of core samples and 2D generated structure was controlled through average pore diameter and structure morphology. The manufactured micromodels were used for surfactant compositions screening aiming to demonstrate the technology capabilities for further testing of various enhanced oil recovery (EOR) chemicals.Thus, several surfactants were examined in bulk employing standard screening procedures (stability evaluation, interfacial tension (IFT) measurements and phase behavior test with oil), and then were investigated in transparent microfluidic chips. Visualization of fluid flow in the porous structure is a primary advantage of microfluidics application for EOR. Hence, surfactant coreflooding-on-a-chip enabled correlation of IFT behavior of various surfactants with recovery efficiency, fast detection of in-situ emulsification and fluid flow distribution analysis in the porous media. Generally, symbiosis of two advanced technologies, i.e. microfluidics and digital core modeling, facilitated significant speed up of laboratory tests and reduce of their cost.

Effects of the Characterization Methods of Heptane Plus Components (C7+) on the Phase Behavior of Volatile Fluids

For reservoir fluids with strong volatile tendencies, such as gas condensate and volatile oil, the determination of the characteristic parameters of the equation of state has a great influence on the fluid phase behavior and subsequent reservoir engineering, production engineering, and surface facilities design calculations. However, the process of characterizing reservoir fluid lacks a unified and standardized procedure, and the methods are largely empirical and rather complicated. In this paper, three main stages are defined for the characterization of the equation of state parameters for these volatile reservoir fluids, including (1) determining the C7+ distribution, (2) calculating the equation of state parameters for the C7+ single-carbon component, and (3) lump components. The typical calculation methods in each step and their effects on the fluid phase behavior calculations are quantitatively analyzed and compared. Finally, the workflow and the suitable characterization methods for gas condensate and volatile oil phase behavior calculations are selected. The results show that C7+ distribution and C7+ single carbon component properties have a greater influence on the phase behavior prediction of condensate gas and volatile oil, while the lumping of C7+ single carbon component has relatively little influence.

Deep Eutectic Solvent as a New Zeta Potential Altering Chemical for Sand Agglomeration.

Fines migration can cause various issues, such as plugging of the sand screen and damage to tubings. There are two chemical sand control methods: consolidation and agglomeration. Consolidation works by injection of a solvent into the formation to harden over time and hold the sand in place, while agglomeration works by altering chemical properties of the sand surface to attract and clump up sand. Various chemicals have been used for research in sand control. Some chemicals for consolidation, mostly resins, have been effective in consolidating sand but may cause permeability impairment, which will reduce production. Some chemicals for agglomeration such as a polymer with amines have been less effective or are nonbiodegradable. In this work, a novel deep eutectic solvent (DES) and ionic polymer combination as a fines stabilizer is formulated in-house and tested through extensive experimental study. The development of chemicals is based on agglomeration principles which determine the range of zeta potential reduction that can be achieved to destabilize, coagulate, and flocculate the fine particles together with different combinations of DESs and ionic polymers tested systematically using the design of experiment (DoE) method. The chemicals are then tested for compatibility with reservoir fluids in the jar test. The optimized formulation is characterized by thermogravimetric analysis (TGA) for limit of temperature degradation and laser particle size analysis (LPSA) for the extent of particle size. The novelty of this work is the development of a greener and more cost-saving in-house DES and ionic polymer combination as a fines stabilizer chemical, which is effective for both injection or production wells after stimulation or enhanced oil recovery (EOR) treatments. Due to the tunable nature of the DES, the formulated chemical can be tailored for various reservoir conditions to cater to specific requirements.

Sensitive Monitoring of the Minimum Inhibitor Concentration under Real Inorganic Scaling Scenarios.

Flow assurance is a long-term challenge for oil and gas exploration as it plays a key role in designing safe and efficient operation techniques to ensure the uninterrupted transport of reservoir fluids. In this regard, the sensitive monitoring of the scale formation process is important by providing an accurate assessment of the minimum inhibitor concentration (MIC) of antiscale products. The optimum dosage of antiscale inputs is of pivotal relevance as their application at concentrations both lower and higher than MIC can imply pipeline blockages, critically hindering the entire supply chain of oil-related inputs and products to society. Using a simple and low-cost impedimetric platform, we here address the monitoring of the scale formation on stainless-steel capillaries from its early stages under real topside (ambient pressure and 60 °C) and subsea (1000 psi and 80 °C) sceneries of the oil industry. The method could continuously gauge the scale formation with a sensitivity higher than the conventional approach, i.e., the tube blocking test (TBT), which proved to be mandatory for avoiding misleading inferences on the MIC. In fact, whereas our sensor could entail accurate MICs, as confirmed by scanning electron microscopy, TBT suffered from negative deviations, with the predicted MICs being lower than the real values. Importantly, the impedance measurements were performed through a hand-held, user-friendly workstation. In this way, our method is envisioned to deliver an attractive and readily deployable platform to combat the scale formation issues because it can continuously monitor the salt precipitation from its early stages and yield the accurate determination of MIC.

Reservoir Damage Induced by Water-Based Fracturing Fluids in Tight Reservoirs: A Review of Formation Mechanisms and Treatment Methods

Reservoir Damage Induced by Water-Based Fracturing Fluids in Tight Reservoirs: A Review of Formation Mechanisms and Treatment Methods

Prototyping disruptive self-sufficiency power machines composed by cascaded power units based on thermo-hydraulic actuators

This research focuses on developing a prototype for a disruptive Self-Sustaining Power Machine (SSPM) that consists of cascaded power units (PUs). Each PU integrates thermo-mechanical and thermo-hydraulic actuators to drive hydraulic pumps connected to generators. The prototype's design leverages two thermal cycle types, sVsVs and VsVs, which enable self-sustaining operations by employing several strategic capabilities that challenge the limitations of second-kind perpetual motion machines (PMMs). Therefore, key capabilities include: 1- Performing useful mechanical work through the expansion and contraction of the Thermal Working Fluid (TWF) by adding and removing heat. 2- Utilizing recovered heat through potential superposition techniques, thereby upgrading the heat to a higher grade, which enhances heat recovery strategies. 3- Designing an efficient energy transfer chain from thermal to electrical energy via thermo-mechanical or thermo-hydraulic actuators, a hydraulic energy drive system, and conversion from hydraulic to electrical energy. 4- Configuring the system to achieve more useful work than the heat added to the initial PU downstream. Two main prototype types are proposed to demonstrate these proposed capabilities: 1- Continuous motion using the sVsVs thermal cycle, with volumetric reservoirs for thermal working fluids (TWF) located outside the thermo-mechanical or thermo-hydraulic actuators. 2- Discontinuous motion using the VsVs thermal cycle, with volumetric reservoirs for TWF located inside the active volume of the thermo-mechanical or thermo-hydraulic actuators. The prototypes were evaluated through case studies using air and helium as real TWFs. Results indicate that the SSPM composed of five cascaded PUs operating on an sVsVs cycle achieved a global efficiency of 149.6% (SSI of 49.6%) with helium and 126% (SSI of 26%) with air. In contrast, the VsVs cycle yielded a global efficiency of 183% (SSI of 83%) with helium and 133% (SSI of 33%) with air