Bubble Point Pressure Research Articles

Field experiments and main understanding of shale oil hydraulic fracturing

To understand the key processes of hydraulic fracturing in shale oil reservoirs, such as artificial fracture initiation and extension, proppant transportation and settlement, and the influencing factors of post-fracture production, many hydraulic fracturing field tests have been conducted in the United States. Examples include the ConocoPhillips tests and the National Hydraulic Fracturing Experiment. The results have promoted the innovation and development of fracturing technology. A good correlation exists between lithological changes and the roughness of artificial fractures. Although numerous artificial cracks are created, the number that can provide oil and gas seepage is relatively small, determined by the effectiveness of these cracks. The settlement of proppants in actual geological formations involves factors such as geology, lithology, fractures, and stress. The pressure data indicate that when the reservoir pressure drops below the bubble point pressure, the decline in production sharply increases. The key variables affecting shale oil well production include the horizontal well position, well spacing, horizontal section length, and sand addition intensity. These technologies are suitable for the adaptive process of China’s terrestrial shale oil fracturing, promoting the development and rapid increase of shale oil production.

High-Performance Composite Membranes: Embedding Yttria-Stabilized Zirconia in Polyphenylene Sulfide Fabric for Enhanced Alkaline Water Electrolysis Efficiency.

Due to their excellent alkali resistance and chemical stability, polyphenylene sulfide (PPS) fabric membranes are widely used in alkaline water electrolysis (AWE) for hydrogen production. However, traditional PPS membranes suffer from poor hydrophilicity, low airtightness, and high area resistance, resulting in high energy consumption and reduced safety in industrial applications. This study addresses the aforementioned issues by coupling 3-(2,3-epoxy propoxy) propyl trimethoxy silane (KH560) via self-condensation to the PPS membrane and blending it with self-synthesized yttrium-stabilized zirconia nanoparticles (YSZNPs). The YSZNPs are loaded onto the modified PPS fiber surface through dip-coating and hot-pressing processes, forming a micro-mechanical interlocking structure that enhances the overall performance of the membrane in practical hydrogen production applications. The findings indicate that the developed composite membrane demonstrate outstanding hydrophilicity, minimal area resistance (0.21 Ω cm2), and elevated bubble point pressure (2.93224bar). Significantly, tests on gas purity indicate that the produced hydrogen and oxygen attain purities of 99.90% and 99.75%, respectively, when evaluated at a current density of 1.5 A cm-2. Moreover, after 500h of electrolysis testing in a simulated industrial environment, minimal decline in membrane performance is observed, highlighting the competitive edge of this composite membrane in the current AWE market.

Analytical and descriptive study of the production behavior for pilot multi-stages hydraulic fracturing wells in southeast Iraq

The hydraulic fracturing technique is a widely used technique worldwide, making it interesting to study. This technique was applied for the first time in Iraq on a tight carbonate reservoir in the Halfaya oil field. In this field, the oil production rates, and flowing pressure were low during production periods reflecting a problem for the development plan designed to increase production using a hydraulic fracture technique. Initially, the hydraulic fracture well showed high oil-producing rates, but then, quickly experienced a high decline failing to keep a stable production rate. To address this problem, it is important to describe and analyze the behavior of pilot hydraulic fracturing wells during their production period, study the inflow performance relationship (IPR), and determine the optimum wellhead pressure above the bubble point pressure (Pb) to avoid loss of lifting energy. Furthermore, it identifies the allowable flow rate to keep stable production, investigates the effect of selecting internal tubing size, and reveals a future production procedure for hydraulic fracture wells. This study reveals that the transient inflow performance relationship observed in the production history of hydraulic fracture well in the tight carbonate reservoir and traditional inflow performance relationship concepts are not applicable. The optimum wellhead pressure for stability in production for Wells w-5 and w-55 is determined to be 750 and 580 psi with optimum rates of 800 and 450 Bbl/D, respectively. The results also showed that producing at a high flow rate may cause a depletion in the fracture potential storage without giving an opportunity for a reservoir to compensate for the produced fluid into fracturing potential storage. The internal tubing size has a passive effect on the hydraulic fracture well, as an increase in size causes an unstable flow zone. Lastly, future production procedures emphasize keeping wellhead pressures stable or increasing them if they drop. This can be accomplished by re-adjusting the choke size according to any changes observed.

Vapor-liquid equilibria of the ternary system of methane + n-decane + n-octacosane at high pressures

Alkane mixture phase equilibria is required for a range of industrial applications, most particularly for the petroleum industries. Mixtures containing light and heavy normal alkanes are of even further significance due to their non-ideal thermodynamic behavior. In this work, for the first time, the ternary system of C1 + C10 + C28 was investigated experimentally to obtain bubble point pressures at various concentrations and temperatures ranging from 373 up to 445 K. The synthetic method of phase equilibrium measurements was utilized, which is known to have high accuracy. The resulting bubble points for the mixtures ranged in pressure from about 3 MPa up to 6 MPa. The data indicated that methane concentrations had the greatest impact, not only on the magnitude of the bubble point pressure, but also on the slope of its temperature trend. The relative concentrations of n-decane and n-octacosane had far less impact on the bubble point curves. The results were also modelled using the Peng–Robinson equation of state, and it was found that this equation has the capability to predict the data with an AARD% of 5.1 %. When temperature-independent binary interaction parameters were optimized to the data, the AARD% reduced to 2.4 %. Although the components vary greatly in size, perhaps the success of the Peng–Robinson equation of state for this mixture could be attributed to the fact that it was developed for hydrocarbon mixtures, and so, a reason for its popularity in the petroleum industries, alongside its simplicity and ease of use.

The effect of hydrocarbon prices and CO2 emission taxes on drainage strategies

Secondary recovery methods, such as water and gas injection, are effective and cost-efficient techniques for enhancing hydrocarbon recovery; however, they are highly energy-intensive, leading to a large environmental footprint. This study provides insights into the challenge of balancing high hydrocarbon demand with the imperative to reduce CO2 emissions from production by estimating how drainage strategies change under varying economic parameters and CO2 tax levels. An operator’s choice of drainage strategy is assumed to be the drainage strategy yielding the highest net present value (NPV). This paper simulates the drainage strategy of an under-saturated oil reservoir, utilizing reservoir simulations and incorporating a mathematical model that represents the production processing plant. This yields hydrocarbon production, the energy required, and the resulting CO2 emissions, all incorporated into an NPV based on hydrocarbon prices and CO2 emission taxes. The drainage strategy is then optimized to maximize NPV for various hydrocarbon prices and several levels of CO2 tax on associated emissions. The findings of this study indicate that increasing gas prices favor reducing reservoir pressure below the bubble point pressure, thereby releasing solution gas and leaving oil in the reservoir. Although lower reservoir pressure reduces the energy required for injection, the resulting increase in gas production necessitates more energy for gas compression, ultimately leading to higher emissions when gas prices rise relative to oil prices. Additionally, this study reveals that for facilities well designed for the present injection and production volumes (greenfield scenarios), the impact of CO2 tax is limited, leading to a single optimal drainage strategy. In contrast, less energy-efficient facilities (brownfield scenarios) exhibit a more pronounced need to optimize drainage strategies in response to variation in CO2 tax, and oil and gas prices. This study indicates that for fields with efficient production facilities, the ratio of gas to oil prices is more important for the drainage strategy than CO2 tax levels, as income from production tends to dominate emission taxes. This implies that hydrocarbon prices are more important for CO2 intensity than CO2 taxes, e.g., a gas price increase relative to oil price promotes higher CO2 intensity due to a shift towards more energy-intensive gas production whereas realistic tax levels for CO2 emissions have only a minor impact. Thus, increasing CO2 tax levels is mainly a measure impacting emissions from fields with inefficient production facilities.

Speed of Sound Measurements of R-1130(E) and an Azeotropic Blend of R-1336mzz(Z)/1130(E)

Sound speed data measured using a dual-path pulse-echo instrument are reported for pure trans-1,2-dichloroethene (R-1130(E)) and an azeotropic blend of cis-1,1,1,4,4,4-hexafluorobutene (R-1336mzz(Z)) and R-1130(E) with a composition of 74.8 mass % R-1336mzz(Z) with the balance being R-1130(E). The azeotropic blend of R-1336mzz(Z)/1130(E) is classified as R-514A in ANSI/ASHRAE standard 34. Liquid phase speed of sound data are reported from just above the saturation pressure of pure R-1130(E) or the bubble point pressure of R-514A to a maximum pressure of 26.7 MPa. The relative combined expanded uncertainty in the speed of sound varies from 0.032 % to 0.148 % with the greatest deviations occurring at the lowest sound speeds. At present, no reference Helmholtz-energy-explicit equation of state (EOS) is available for R-1130(E). Therefore, the reported data for pure R-1130(E) are compared to an extended corresponding states (ECS) model. Deviations between the pure R-1130(E) sound speed data and the ECS model were found to be consistently negative ranging between − 4.1 % and − 3.5 %. The R-514A data are compared to a multifluid model inclusive of the established reference Helmholtz-energy-explicit EOS for R-1336mzz(Z) and ECS model for R-1130(E) with estimated binary interaction parameters. Deviations between the experimental speed of sound data and the multifluid model were also found to be consistently negative. However, deviations from the multifluid model were found to be as great as − 17.1 %. The large deviations from the ECS model and multifluid model underscore the need for a robust Helmholtz-energy-explicit EOS for R-1130(E).

Enhanced Solubility and Miscibility of CO2-Oil Mixture in the Presence of Propane under Reservoir Conditions to Improve Recovery Efficiency

The existence of propane (C3H8) in a CO2-oil mixture has great potential for increasing CO2 solubility and decreasing minimum miscibility pressure (MMP). In this study, the enhanced solubility, reduced viscosity, and lowered MMP of CO2-saturated crude oil in the presence of various amounts of C3H8 have been systematically examined at the reservoir conditions. Experimentally, a piston-equipped pressure/volume/temperature (PVT) cell is first validated by accurately reproducing the bubble-point pressures of the pure component of C3H8 at temperatures of 30, 40, and 50 °C with both continuous and stepwise depressurization methods. The validated cell is well utilized to measure the saturation pressures of the CO2-C3H8-oil systems by identifying the turning point on a P-V diagram at a given temperature. Accordingly, the gas solubilities of a CO2, C3H8, and CO2-C3H8 mixture in crude oil at pressures up to 1600 psi and a temperature range of 25–50 °C are measured. In addition, the viscosity of gas-saturated crude oil in a single liquid phase is measured using an in-line viscometer, where the pressure is maintained to be higher than its saturation pressure. Theoretically, a modified Peng–Robinson equation of state (PR EOS) is utilized as the primary thermodynamic model in this work. The crude oil is characterized as both a single and multiple pseudo-component(s). An exponential distribution function, together with a logarithm-type lumping method, is applied to characterize the crude oil. Two linear binary interaction parameters (BIP) correlations have been developed for CO2-oil binaries and C3H8-oil binaries to accurately reproduce the measured saturation pressures. Moreover, the MMPs of the CO2-oil mixture in the presence and absence of C3H8 have been determined with the assistance of the tie-line method. It has been found that the developed mathematical model can accurately calculate the saturation pressures of C3H8 and/or CO2-oil systems with an absolute average relative deviation (AARD) of 2.39% for 12 feed experiments. Compared to CO2, it is demonstrated that C3H8 is more soluble in the crude oil at the given pressure and temperature. The viscosity of gas-saturated crude oil can decrease from 9.50 cP to 1.89 cP and the averaged MMP from 1490 psi to 1160 psi at 50 °C with the addition of an average 16.02 mol% C3H8 in the CO2-oil mixture.

Effect of porous irregular ZrO2 nanoparticles on the performance of alkaline water electrolysis composite separator membranes under complex conditions

Developing composite separator membranes with low area resistance, high bubble point pressure, and long-term safety and stability is crucial for alkaline water electrolysis for hydrogen production as a key component of electrolyzer systems. In this study, PPS mesh fabric reinforced PSF@ZrO2 composite separator membranes were successfully prepared using the immersion-drawing phase inversion method, with PSF as the alkali-resistant polymer matrix and porous irregular ZrO2 nanoparticles as the hydrophilic additive. The experimental results showed that replacing commercial ZrO2 with porous irregular ZrO2 nanoparticles at an 85 wt% ZrO2 nanoparticle loading improved both bubble point pressure and current transmission efficiency, attributed to the change in the morphological structure of the ZrO2 nanoparticles. The P-Z85 composite separator membrane exhibited highly promising characteristics, with a high bubble point pressure of 3.76 bar and a low area resistance of 0.20 Ω cm2. Stability tests conducted in 30 wt% KOH electrolyte at 80 °C and a current density of 0.65 A cm−2 demonstrated excellent continuous electrolysis stability for the P-Z85 composite separator membrane. These results indicate that the PSF@ZrO2/PPS composite separator membrane prepared in this study exhibits excellent performance in 30 wt% KOH electrolyte, significantly extending its service life.

Impact of Fault and Reef on Reservoir Pressure Behavior and Production Profile: Case Study- South Iraqi Oilfield

The study area, which consists of carbonate, is located in the unstable Mesopotamian basin on the Arabian plate, which makes it a field with high heterogeneity. It has a discrepancy in its bubble point pressure, which raises concerns about the faults or reefs that caused it. The study's main objective is to determine how faults and reefs impact production performance and pressure behavior under a future development strategy. This goal will be achieved by completing the necessary seismic, static, and dynamic models. After re-evaluating the seismic survey data, the seismic analysis detected many irregular amplitudes of reflected events and abrupt discontinuities, indicating either a reef or a fault. The static model was built based on seismic possible results and to make them as inputs for building the reservoir model. Based on the history-matching results, faults were detected, while reefs were ruled out. The development plan was implemented for the next 20 years in four cases, and case four had the most favorable results among all the cases, with production plateauing at 140 MSTB/D and a cumulative volume equal to 1.09 MMMSTB. The reservoir pressure behavior shows a hierarchical drop in all cases, with some differences, including a sharp decline in the area of the proposed wells and the fault, which has become a compartment that prevents reservoir compensation from adjacent regions.

تحسين علاقة المرهون لضغط نقطة الفقاعة للنفط الخام الليبي

Accurate estimation of crude oil bubble point pressure plays a vital role in many petroleum engineering calculations, such as reserve estimation, material balance, reservoir simulation, production equipment design, and optimization of well performance. The Pb can be measured in the pressure-volume-temperature (PVT) experiments. Nonetheless, the PVT measurements have limitations, such as being costly and time-consuming. In this paper, the Al-Marhoun correlation for bubble point pressure for black oil reservoirs is improved using the linearization of non-linear regression techniques to fit Libyan crudes accurately. A total of 62 PVT data reports taken from various Libyan oil fields were used in the study. The PVT data consist of an oil gravity range of 24.7 ºAPI to 46.8 ºAPI and bubble point pressures of 123 psig to 6100 psig. Statistical error analyses and graphical methods were used to evaluate the original and modified Al-Marhoun correlations. The results showed that the improved Al-Marhoun correlation exhibits significantly lower average absolute error and deviation than the published ones. The correlation coefficient of R2 of the improved Al-Marhoun correlation is 96.70%, and the average percent error (APE) is 0.70% with a standard deviation (SD) of 14.70.

Investigation of nano-confinement effects on asphaltenic crude oil phase behavior in tight and shale reservoirs: Modeling using CPA-EOS

As a result of strong molecule–molecule and molecule–wall interactions, phase behavior in confined fluids differs significantly from that in bulk fluids. Asphaltene precipitation is a challenging issue for both conventional and unconventional (nano-scale) porous media. In this study, a new model based on cubic-plus-association equation of state (CPA-EOS) was developed for studying phase behavior of asphaltenic crude oil and asphaltene precipitation in nanoporous media. The developed model considers confinement phenomena including shift in the critical properties of components, high capillary pressure, and adsorption/desorption of fluid components on rock surface. For this purpose, necessary modifications were performed on both the EOS and phase equilibria calculations. The developed model was then used to analyze two-phase (vapor–liquid) and three-phase (vapor–liquid–asphaltene) behavior in confined systems. Results demonstrated that confinement phenomena shrink the two-phase envelope and shift the critical point of the mixture. It is also shown that instability of asphaltene in the solution is higher in nanoporous media and increases with reducing pore size. Therefore, the amount of precipitated asphaltene in nanoporous media is higher than that in conventional systems. As adsorption of components with higher molecular weights is more than that of low-molecular weight compounds, the crude oil sample is enriched with lighter components and hence, due to adsorption, bubble point pressure increases, upper branch of dew point curve shifts downward and its lower branch shifts upward, and asphaltene instability increases. Neglecting confinement phenomena results in overestimation or underestimation of saturation pressures as well as asphaltene upper and lower onset points and the proposed model can be of high importance in predicting the extent of asphaltene precipitation during natural depletion or solvent injection in tight oil reservoirs.

A compositional numerical study of vapor–liquid-adsorbed three-phase equilibrium calculation in a hydraulically fractured shale oil reservoir

The development of carbon capture, utilization, and storage technologies has notably advanced CO2-enhanced oil recovery (EOR) in shale oil reservoirs, which are characterized by abundant nanopores. These nanopores induce unique phase behaviors in hydrocarbons, challenging traditional phase equilibrium calculation methods. This paper presents a novel three-phase thermodynamic model (vapor–liquid-adsorbed three-phase equilibrium calculation) that addresses these challenges by considering the nanopore capillary pressure, critical parameter transitions, and material exchange between the adsorbed and bulk phases. Grounded in the multicomponent Langmuir–Freundlich adsorption equation and the Peng Robinson equation of state, this model is integrated into the MATLAB Reservoir Simulation Toolbox using an embedded discrete fracture model framework, enabling detailed study of CO2 and hydrocarbon phase behaviors within shale oil nanopores. The results reveal that there are significant nano-constrained effects on multicomponent fluid phase behavior, particularly in pores smaller than 20 nm, leading to notable changes in bubble and dew point pressures, as well as critical condensation pressures and temperatures. CO2 injection further complicates the system, enhancing interactions and expanding the coexistence region of the liquid and gas phases on the pressure–temperature diagram, especially across varying pore sizes. Optimization research on CO2 huff and puff technical parameters for shale oil reservoirs suggests the following optimal settings: a CO2 injection rate of 100 t/day, a shut-in time of 30 days, and six huff and puff cycles. The results of this study offer critical insights into CO2-EOR mechanisms in shale oil reservoirs and emphasize the importance of nanopore properties in EOR.

Bubble Point Measurements of cis-1,1,1,4,4,4-Hexafluorobutene [R-1336mzz(Z)] + trans-1,2-Dichloroethene [R-1130(E)] mixtures

Saturation pressures of pure R-1336mzz(Z) and R-1130(E) and bubble point pressures of three R-1336mzz(Z)/1130(E) blends were measured from 265 K to 360 K. For each pure refrigerant or refrigerant blend, a total of twenty unique saturation pressures or bubble points were measured. In total 100 unique state points were obtained. Presently, no Helmholtz-energy-explicit type equation of state (EoS) is available for R-1130(E). While an extended corresponding states EoS for R-1130(E) is available to estimate the properties of the R-1336mzz(Z)/1130(E) blend, this model does not resolve the azeotropic behavior of the mixture. Therefore, the perturbed-chain statistical-associating fluid theory (PC-SAFT) EoS is used to model the vapor–liquid equilibria of the R-1336mzz(Z)/1130(E) blend. PC-SAFT model parameters are reported, and the overall performance of the model is characterized by deviations from the experimental data.

Nanofluidic Study of Multiscale Phase Transitions and Wax Precipitation in Shale Oil Reservoirs

During hydraulic fracturing of waxy shale oil reservoirs, the presence of fracturing fluid can influence the phase behavior of the fluid within the reservoir, and heat exchange between the fluids causes wax precipitation that impacts reservoir development. To investigate multiscale fluid phase transition and microscale flow impacted by fracturing fluid injection, this study conducted no-water phase behavior experiments, water injection wax precipitation experiments, and water-condition phase behavior experiments using a nanofluidic chip model. The results show that in the no-water phase experiment, the gasification occurred first in the large cracks, while the matrix throat was the last, and the bubble point pressure difference between the two was 12.1 MPa. The wax precipitation phenomena during fracturing fluid injection can be divided into granular wax in cracks, flake wax in cracks, and wax precipitation in the matrix throat, and the wax mainly accumulated in the microcracks and remained in the form of particles. Compared with the no-water conditions, the large cracks and matrix throat bubble point in the water conditions decreased by 6.1 MPa and 3.5 MPa, respectively, and the presence of the water phase reduced the material occupancy ratio at each pore scale. For the smallest matrix throat, the final gas occupancy ratio under the water conditions decreased from 32% to 24% in the experiment without water. This study provides valuable insight into reservoir fracture modification and guidance for the efficient development of similar reservoirs.

Monte Carlo Simulation of the CO2 Flooding Efficiency at a Core Scale for Different Oil Compositions

The evaluation of water-alternating-gas (WAG) efficiency and profitability is complicated by a large number of reservoir, operating, and economic parameters and constraints. This study aims at understanding the influence of the oil composition on different WAG injections. By employing compositional reservoir modeling and the Monte Carlo method to characterize the diversity of oils occurring in nature, we simulate the microscopic displacement efficiency of CO2 flooding when it is applied to both light- and heavy-oil reservoirs. We find that the economic performance of WAG in both miscible and immiscible scenarios is mainly characterized by the dimensionless injection rate and the oil density at surface conditions. Neither the bubble point pressure nor the minimum miscibility pressure can be used for the quantification of the optimal WAG parameters. We present our estimates of the best strategies for the miscible and immiscible injections and verify some of our previous results for randomly sampled oils. In particular, we demonstrate that CO2 flooding is better to apply at higher-dimensionless injection rates. We show that the injection of CO2 organized at a light-oil reservoir results in a higher profitability of WAG, although this comes at the cost of lower carbon storage efficiency.

Simulation of the thermal field in reservoir during the filtration of live oil and water with considering the heat of oil degassing and thermodynamic effects

In the process of water invasion of reservoir under conditions of pressure decrease below the bubble point pressure of oil with dissolved gas, when oil degasses, an area of three-phase flow of oil, water and gas appears in the reservoir. In this case, each of the phases makes a certain contribution to the formation of the thermal field in the reservoir, due to the thermodynamic effects shows and the heat of oil degassing. The thermal field forming is influence many parameters, for example, the initial water cut of formation, gas oil ratio, the ratio of reservoir pressure and bubble point pressure of oil with dissolved gas, the ratio of reservoir pressure and bottomhole pressure, etc. The thermohydrodynamic processes occurring in this case carry information about the formation and the near wellbore zone. One of the directions for using the features of the formation of the temperature field in this case is the use of thermometric studies of wells to diagnose the condition of the well and formation. Reservoir water invasion under the condition of oil degassing leads to a change in the temperature distribution in the formation, which can be used in diagnosing the identifying sources of water invasion. Using a numerical method for solving the equations of mass conservation and heat influx during non-isothermal three-phase filtration, in this work are studied the features of the formation of the temperature field in an oil-saturated reservoir with an initial water cut during oil degassing. As a result of calculations for various ratios of the initial water cut of the formation and the gas oil ratio, temperature dependences were obtained for different of well operation times. The obtained dependences of temperature on water cut and gas oil ratio can be used as palettes for quantitative evaluation of water inflow rates from formations.

Developing statistical and machine learning models for predicting CO2 solubility in live crude oils

CO2 solubility in crude oil primarily affects the viscosity and swelling capacity of oil and determines the displacement efficiency of CO2 flooding during the enhanced oil recovery process. Dissolution of CO2 into crude oil also ensures safe and permanent storage of CO2 in depleted formations via solubility trapping. This study employed statistical and machine learning algorithms to develop precise and stable predictive models for estimating CO2 solubility in crude oils with dissolved gas. Recognizing the limitations of existing experimental data on CO2 solubility for live oils (crude oils with dissolved gas), we introduced a novel approach employing statistical and machine learning techniques for developing accurate and robust predictive models. Our methodology combined regularization, k-fold cross-validation, and statistical significance tests to ensure the robustness of the models, practices not considered in the previous studies. A linear regression model with L2 regularization is developed as the base model and compared with a 2nd order polynomial model and an ensemble feed-forward neural network (FNN) model integrated with gradient boosting (GB). The incorporation of GB into the neural network capitalizes on the additive sequence of FNN models, thereby enhancing the accuracy and reliability of predictions. Moreover, an improved user-accessible and easily implementable correlation is proposed to estimate CO2 solubility in live crude oils at diverse operating conditions as a function of reservoir temperature, saturation pressure, bubble-point pressure, oil molecular weight, and specific gravity. The performances of the developed model and the correlation are compared against the literature models and correlations. The FNN model with an overall R2 score of 0.9978, average absolute relative deviation (AARD) of 1.54 %, and root mean squared error (RMSE) of 0.0083 outperformed the previously published models and correlations. The new correlation, while being relatively simpler than previously published correlations, showed similar predictive performance with an overall R2 score of 0.9817, AARD of 4.98 %, and RMSE of 0.0225. The model and the correlation can be used to estimate CO2 solubility in live crude oils with 0.67 to 0.97 specific gravity for reservoir temperatures and pressures in the range of 28 to 124 °C and 3.23 to 32.76 MPa, respectively.

Investigating the Bubble Point Pressure Discrepancy by History Matching for Mishrif Reservoir, Southern Iraqi Oil Field

Carbonate reservoirs have been a primary focus for academics and oil and gas companies for many years. However, the complex nature of these rocks has always posed challenges. This is particularly true in the study area, which is located in the unstable Mesopotamian Basin, where multiple oil fields produce hydrocarbons from NW-SE-trending anticlines along the Zagros Fold-Thrust Belt. The primary goal of reservoir simulation is to forecast reservoir performance and apply different techniques to improve hydrocarbon recovery under different conditions. The study area faces a problem of discrepancy in the bubble pressure at the same reservoir unit, which is attributed to the faults in the Mishrif reservoir. A study was conducted to investigate the causes of this phenomenon. The proposed method for verification involves simulating history matching using the Petrel platform after building two geological models on the probability of the fault and the reef; as a result of seismic survey interpretation. Field data for gas production of the reservoir and Pressure-Volume-Temperature analyses, especially the wells (well pad F), were used to determine the causes of the discrepancy. The current study found that the calculated and observed data match more consistently in the case of the fault rather than in the case of the reef, indicating the presence of fault in the area near the well pad F. This caused compartmentalization, leading to the discrepancy in the bubble pressure. This study could significantly improve regional exploration, especially in Iraq.

High chemical stability poly(oxindole biphenylene)/ZrO2 porous separator for alkaline water electrolysis

Porous separators are essential for alkaline electrochemical energy technologies, such as alkaline water electrolyzers (AWEs). These separators are promising alternatives to dense membranes because they offer the potential for low cost and high ionic conductivity. However, two significant challenges in developing efficient and durable alkaline energy systems are the suppression of hydroxide ions-induced degradation and the reduction of gas permeation in porous separators. Compared to hydrophobic polysulfone (PSF), KOH-doped poly (oxindole biphenylene) (POBP) is a highly stable ion-solvating polymer that can conduct both potassium and hydroxide ions. Building upon this, a series of porous separators based on POBP polymer with different zirconia loads were designed using NIPS to investigate the chemical stability and water electrolysis performance where the Z60 separator exhibits remarkable characteristics, including low area resistance (0.227 Ω cm2), high bubble point pressure (0.813 MPa), low H2 permeability (0.5 L min−1·cm−2) and exceptional 5040 h of ex-situ durability in 6 M KOH at 80 °C. Furthermore, the Z60 diaphragm showed a higher breaking time and lower weight loss after 261 h at 80 °C in the Fenton reagent, with the remaining mass being Z60 was 38 %. Notably, the Z60 diaphragm, when equipped with Ni–Al catalysts, achieved a current density of 0.5 A/cm2 at 1.7 V, which surpasses that of Zirfon (0.5 A/cm2 at 1.8 V). More importantly, when using Ni foam catalysts, the Z60 diaphragm demonstrated stable operation under 0.125 and 0.5 A/cm2 current densities at 80 °C for more than 900 h and 1200 h, significantly improving the durability of the porous separators. The results of this study showed that the blending of POBP can lead to the development of highly chemically stable porous diaphragms, thereby opening up a new avenue for advanced AWEs.

Analysis of Relatively Short Variable Rate “Noisy” Well Test Data Using Non-Linear Deconvolution

Short well test data are pressure-rate-time data that are not long enough to be used to infer the reservoir boundary model and are very common in the oil and gas industry. Short rate well test data may occur when companies try to cut costs of well test jobs or mostly due to improper well test design. Nevertheless, one may wish to extract the most amount of information from this limited data because the de-convolve response can allow the reservoir engineer to make the best use of the available data in selecting a suitable interpretation model by narrowing down the possible boundary models and also providing a reliable estimates of model parameters. The aim of this study is to demonstrate the usefulness and significance of pressure-rate deconvolution in analyzing relatively short variable rate data using a hypothetical case study. The simulation was carried out using Sapphire’s test design module by assuming the presence of an exploratory well in an oil reservoir above bubble point pressure. Further assumption is that the reservoir is homogenous, therefore the possibility of a changing wellbore model was neglected from the analysis. The computer codes for the simulation were inputted using python programming language. We observed from the study that although pressure and flow rate relationship can be nonlinear, the problem can be formulated as a linear problem and the nonlinearity is expressed in the features of the reservoir. The simulation results were satisfactory using the test case and deviations between model parameters and actual reservoir parameters used in simulation was shown to have an absolute value less than 8% which is within acceptable engineering limits.