Pressure Volume Temperature Research Articles

Calibrating the Reservoir Model of the Garraf Oil Field

History matching is a significant stage in reservoir modeling for evaluating past reservoir performance and predicting future behavior. This paper is primarily focused on the calibration of the dynamic reservoir model for the Meshrif formation, which is the main reservoir in the Garraf oilfield. A full-field reservoir model with 110 producing wells is constructed using a comprehensive dataset that includes geological, pressure-volume-temperature (PVT), and rock property information. The resulting 3D geologic model provides detailed information on water saturation, permeability, porosity, and net thickness to gross thickness for each grid cell, and forms the basis for constructing the dynamic reservoir model. The dynamic reservoir model integrates a variety of inputs, including well position and trajectory, well completion data, initial reservoir condition, and daily production/injection rates. The validation process involves comparing the original oil reserve derived from the geological model with the one obtained from the dynamic reservoir model. To achieve an accurate history matching, the calibration process has been performed by aligning observed data with simulation results. This involves focusing on production/injection data for each well and pressure measurements for selected wells. Notably, horizontal permeability is identified as a critical parameter in this study, which is adjusted iteratively to achieve a robust match for individual wells and the entire field. Thus, Successful calibration facilitates the subsequent stage and future scenarios allowing for the exploration of different conditions to predict the performance of the Garraf oilfield. This comprehensive approach improves the reliability of reservoir predictions, facilitating well-informed decision-making in reservoir management.

Effect of Predisolved Natural Gas on CO2 Solubility in Water With Various Salinities at Reservoir Conditions

Dissolution of CO2 in saline waters is considered one of three main CO2 trapping mechanisms, along with structural/stratigraphic trapping and mineralization. CO2 can dissolve in fresh/saline water under typical reservoir pressure and temperatures. Its solubility is dependent on pressure, temperature, and salinity. CO2 solubility studies typically consider saline water or fresh water as a liquid without any predissolved gases. The reality is formation water may contain appreciable dissolved gases for all pressure and temperature conditions. An example of gas-water ratio (GWR) can be ~1 scf/stb for formation water in an oil reservoir and ~5 to 6 scf/stb for a deep saline aquifer. Therefore, it is essential to quantify the effect of brine salinity on CO2 solubility in “live” saline waters. Just as “live” oil denotes reservoir oil that contains solution gas, we define “live” brine as saline water that includes dissolved gases. Conversely, “dead” brine refers to saline water devoid of any dissolved gas content. Two sets of experiments were conducted under typical reservoir conditions. The first set of experiments evaluated the CO2 solubility in live formation water. The second set of experiments evaluated how variation in the live brine salinity affected CO2 solubility. These experiments involved 1) synthesis of the brine, 2) synthesis of natural gas mixture, 3) recombination of live formation water with a natural gas mixture and transfer into a high-pressure and high-temperature pressure-volume-temperature (PVT) visual cell, 4) CO2 addition to the PVT cell, and 5) bubblepoint pressure determination within the PVT cell. The results showed that CO2 solubility in live formation water is significantly less than that in “dead” water under reservoir conditions. In addition, the brine salinity affects CO2 solubility in live formation water by further reducing CO2 solubility with increasing live brine salinity. As the brine salinity increases, very little CO2 can be dissolved in the live brine once it reaches a certain solubility. An understanding of CO2 dissolution in live saline water is essential for future CCUS evaluation and execution.

Holistic Evaluation of Reservoir Oil Viscosity in Breidablikk Field – Including Mud Gas Logging Approach

Breidablikk is a green field on the Norwegian Continental Shelf that just started the preproduction drilling of 23 wells in two structures. We have two reservoir fluid samples from exploration wells in each structure with relatively high viscosity of 4 and 8 cP, respectively. Our dynamic reservoir simulations on the Breidablikk Field indicate that any change in the viscosity in each direction can lead to a 20 to 30% difference in oil recovery. Therefore, updating our reservoir models with the viscosity distribution in the field along with the drilling activities is important. Currently, our models assume homogeneous reservoir oil viscosities across each structure. In this study, our primary aim is to conduct a holistic evaluation of the reservoir oil viscosity, using multiple methods to determine the most effective approach for qualitatively mapping the oil viscosity across the field, distinguishing between the low- and high-viscosity regions. The technologies chosen for this assessment are standard mud gas data, advanced mud gas data, and analysis of oil extracts from cuttings, given they have previously demonstrated their capability to estimate fluid properties while drilling or within a limited time frame, as evidenced by the work of Cutler et al. (2022). The methods were compared using pressure/volume/temperature (PVT) measurements as a benchmark. As of today, this method is considered the most reliable to obtain reservoir fluid properties, and in consequence, these measurements serve as the reference viscosity values in the study. The results of our analysis in Breidablikk show that an approach based on advanced mud gas data provide an oil quality classification that distinguishes between high- and low-viscosity reservoir oils, using the ethane/n-pentane ratio as the best parameter correlated to reservoir oil viscosity in Breidablikk. The threshold for the two viscosity regions is identified from a reservoir fluid database from the Breidablikk-Grane area, and the oil viscosity region estimated from advanced mud gas data agrees well with the PVT measurements. The viscosity estimation using a standard mud gas approach based on methane to propane compositions indicates that this technology cannot correctly differentiate between low- and high-viscosity region wells in the Breidablikk Field. Hence, it is not recommended. Further findings from our analysis indicate that the utilization of oil-based mud, combined with a high drilling speed, significantly affects the quality of the cuttings in Breidablikk. Consequently, the application of traditional geochemical analysis methods on cutting extracts is challenging. Therefore, this method is not recommended for the qualitative identification of the viscosity region of a given well. Benchmarking all available technologies allows us to select a real-time, reliable, and cost-efficient method to qualitatively estimate reservoir oil viscosity in Breidablikk. The selected method is field-specific and not general for other heavy oil fields. In summary, providing an accurate reservoir oil viscosity mapping at an early stage in field development plays a crucial role in the further optimization of drilling targets and ultimately leads to improved oil recovery (Halvorsen et al., 2016; Maraj et al., 2021).

Phase behavior of gas condensate in porous media using real-time computed tomography scanning

The phase behavior of gas condensate in reservoir formations differs from that in pressure–volume–temperature (PVT) cells because it is influenced by porous media in the reservoir formations. Sandstone was used as a sample to investigate the influence of porous media on the phase behavior of the gas condensate. The pore structure was first analyzed using computed tomography (CT) scanning, digital core technology, and a pore network model. The sandstone core sample was then saturated with gas condensate for the pressure depletion experiment. After each pressure-depletion state was stable, real-time CT scanning was performed on the sample. The scanning results of the sample were reconstructed into three-dimensional grayscale images, and the gas condensate and condensate liquid were segmented based on gray value discrepancy to dynamically characterize the phase behavior of the gas condensate in porous media. Pore network models of the condensate liquid ganglia under different pressures were built to calculate the characteristic parameters, including the average radius, coordination number, and tortuosity, and to analyze the changing mechanism caused by the phase behavior change of the gas condensate. Four types of condensate liquid (clustered, branched, membranous, and droplet ganglia) were then classified by shape factor and Euler number to investigate their morphological changes dynamically and elaborately. The results show that the dew point pressure of the gas condensate in porous media is 12.7 MPa, which is 0.7 MPa higher than 12.0 MPa in PVT cells. The average radius, volume, and coordination number of the condensate liquid ganglia increased when the system pressure was between the dew point pressure (12.7 MPa) and the pressure for the maximum liquid dropout, Pmax (10.0 MPa), and decreased when it was below Pmax. The volume proportion of clustered ganglia was the highest, followed by branched, membranous, and droplet ganglia. This study provides crucial experimental evidence for the phase behavior changing process of gas condensate in porous media during the depletion production of gas condensate reservoirs.

Effect of Pressure and Temperature Variation on Wax Precipitation in the Wellbore of Ultradeep Gas Condensate Reservoirs

Summary To investigate the wax precipitation mechanism of condensate in a wellbore during the ultradeep gas condensate reservoir development, condensate samples were prepared in this work. Changes in the temperature and pressure of fluid flow in the wellbore are simulated by a high-temperature and high-pressure pressure/volume/temperature (PVT) system. This simulation explores their influences on the wax precipitation of the condensate produced from the target reservoir. The results show that the temperature decrease weakens the wax molecular movement activity and promotes the precipitation of wax, resulting in the expansion of the pressure range in which wax precipitation occurs in the system. Meanwhile, decreasing the pressure promotes wax aggregation by increasing van der Waals forces between wax molecules, thereby increasing the wax precipitation rate. At different temperatures, the wax precipitate amount first increases and then decreases with decreasing pressure, which is determined by the wax solubility and remaining content in the system. Since the solubility of a low carbon number component is more sensitive to temperature and pressure changes than that of a high carbon number component, in the early stages of experimental temperature and pressure decreases, the precipitation of coarse crystalline wax with carbon numbers ranging from C16 to C30 is more active than that of microcrystalline wax with carbon numbers exceeding C30. The remaining amount of the former component in the system decreases rapidly, and its precipitation capacity weakens, thus increasing the amount of the latter component in the precipitated wax during the later stage of experiments; this trend corresponds to the shift of the curve peak of the wax carbon number distribution to an abscissa interval with the relatively high carbon numbers. This work can provide reference data for the prediction of the well depth at which the wax precipitation occurs and the wax composition, aiming to promote the implementation of wellbore wax blockage prevention programs.

Insights into CO2 huff-n-puff mechanisms from laboratory experiment and single-well pilot test in the Lucaogou tight oil reservoir, Jimsar sag, China

CO2 huff-n-puff has been accepted as an effective technique to improve oil recovery in tight oil reservoirs. Even though CO2 EOR mechanisms were extensively investigated from laboratory experiments, the links of experimental results to field-scale performance have not been widely investigated as few pilot tests were conducted. In this study, laboratory experiments and CO2-huff-n-puff pilot test were performed. First, phase behaviors of the Lucaogou crude oil and oil-CO2 mixtures were investigated via Pressure-Volume-Temperature (PVT) tests including flash evaporation, constant composition extension (CCE), and CO2 injection and slim tube tests, respectively. Experimental results showed that due to the higher concentration of the intermediate components, the saturation pressure of the Lucaogou crude oil is 6.18 MPa, which is much smaller than the initial and current formation pressures. The oil viscosity decreased from 24.8 mPa s to 3.0 mPa s and swelling factor increased to 1.848 after about 85 mol% CO2 dissolved. Moreover, slim tube test showed the minimum miscible pressure of the Lucaogou crude oil is 24.28 MPa, which is smaller than the current formation pressure, indicating multi-contact miscibility could be reached easily. Second, fracturing fluid imbibition and CO2 huff-n-puff experiments were carried out to evaluate the performance of CO2 EOR after fracturing. The oil recovery factor increased after imbibition time and the number of huff-n-puff cycles, and was impacted by petrophysical properties, like porosity and pore structure. In addition, performance of CO2 huff-n-puff pilot test in the J30 well was reported. Approximately 1.9% of original oil in place was recovered after one huff-n-puff cycle, showing a significant potential of CO2 EOR in the Lucaogou tight formation. Analysis of oil production rate, composition and density of produced oil shows the dominant EOR mechanisms in the early production stage were miscibility and CO2 vaporization, then viscosity reduction. Findings from this study will provide insights on CO2 EOR in tight oil reservoirs.

Enhanced Reservoir Description via Areal Data Integration and Reservoir Fluid Geodynamics: A Case Study From Deepwater Gulf of Mexico

Accurate reservoir characterization is vital for effective decisions made throughout the life cycle of an oilfield reservoir, including management and development. Of all the components of reservoir description, hydraulic connectivity carries the highest amount of uncertainty, where inaccurate connectivity evaluation often results in production underperformance. Shortcomings are faced when applying conventional approaches of connectivity assessment. Seismic surveys are not always sufficient to evaluate lateral connectivity as detected faults can be transmissive or partially transmissive, while some faults are below the detection limits of seismic amplitude measurements. Vertical connectivity represents another uncertainty, where pressure measurements and well logs are often either unable to detect the baffles along oil columns or cannot assess whether detected baffles are relevant seals or flow diverters. Although conventional downhole fluid analysis (DFA) workflows have proven effective in delineating reservoir connectivity, enough DFA data are not always available, and with added complexity, uncertainties arise. Additionally, while equilibrated asphaltene gradients, measured through DFA probes, imply connectivity, ongoing reservoir fluid geodynamics (RFG) processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. Thus, a comprehensive assessment approach, that utilizes all available data streams, is needed to overcome the significant spatial complexity associated with moderately and heavily faulted reservoirs. In this paper, we employed our recently introduced interpretation workflow to evaluate the connectivity of a heavily faulted reservoir in the deepwater Gulf of Mexico. The field was divided into five investigation areas penetrated by 12 wells. Areal downhole fluid analysis (ADFA) was applied to assess local connectivity leading to reservoir-scale connectivity. Through integrating fluid/dynamic and rock/static data, each data type provided insights that were pieced together to enhance consistency and reduce uncertainty. Analyzed data included pressure-volume-temperature (PVT) reports, pressure surveys, well logs, and geochemistry. The study resulted in a verifiable connectivity description where faults, previously regarded as sealing, were classified into sealing or partially transmissive faults; unresolved faults were detected. Fault-block migration was detected, and fault throw was estimated; asphaltenes behavior was used to deduce original field structures prior to faulting. We also examined RFG processes to investigate oil biodegradation, where an asphaltene clustering trend was observed, causing high oil viscosities toward the bottom of one sandstone. A correlation was then derived and successfully implemented to estimate oil viscosity.

Study of Supercritical State Characteristics of Miscible CO2 Used in the Flooding Process

Carbon dioxide flooding is a strategic replacement technology for greatly enhancing oil recovery in low-permeability oilfields, which includes social benefits resulting from carbon emission reduction and economic benefits owing to the improvement of oil recovery. Therefore, it is of great significance to develop and apply the technology of CO2 flooding and storage in the petroleum industry. In reservoir conditions, CO2 is usually under a supercritical state, presenting both low viscosity and high diffusivity of a gaseous state and high density of a liquid state. The special phase behavior of CO2 directly affects its extraction capacity, resulting in the change of miscible behavior between CO2 and crude oil. In this paper, the ultra-high-pressure–high-temperature pressure–volume–temperature (PVT) system was used to evaluate the phase characteristics of CO2 during the process of reservoir development. The phase behaviors of the CO2/CH4/N2 crude oil system were compared and analyzed. Moreover, the matching mechanism between supercritical CO2 characteristics and oil–gas system miscibility was investigated and defined. This work deepened the understanding of the phase characteristics of CO2 in the process of miscible flooding, providing both theoretical guidance for the application of CO2 injection on oilfields and the essential scientific basis for the implementation of CCUS-EOR technology.

Prediction of Part Shrinkage for Injection Molded Crystalline Polymer via Cavity Pressure and Melt Temperature Monitoring

During an injection molding process, different parts of the molded material are subjected to various thermal–mechanical stresses, such as variable pressures, temperatures, and shear stresses. These variations form different pressure–temperature paths on the pressure–volume–temperature diagram. If these paths cannot converge at a specific target volume value during ejection, it often leads to different levels of shrinkage and associated warping, which pose a significant challenge for molders during mold trials and part quality control. The situation is particularly complicated when molding crystalline polymers because the degree of crystallinity depends on the processing conditions and may vary across different locations. In this study, we propose an innovative and practical approach to improving part shrinkage when molding crystalline polymers. For the first time, we utilized melt temperature profile monitoring rather than the previous mold temperature measurement to detect the crystallization process and determine the time taken to complete the crystallization at different melt and mold temperatures. In addition, we used response surface methodology to build a crystallization time prediction model. The feasibility of the prediction model was verified by determining the warpage of parts molded at various cooling times. Based on this model, we varied the packing pressure, packing time, and melt temperatures to determine the correlation with part shrinkage. Through regression analysis, the time-averaged solidification pressure values can accurately control part shrinkage. Two prediction models provide reasonable accuracy and efficiency for part shrinkage control, as demonstrated by subsequent verification experiments.

Twisting instabilities in elastic ribbons with inhomogeneous pre-stress: A macroscopic analog of thermodynamic phase transition

We study elastic ribbons subject to large, tensile pre-stress confined to a central region within the cross-section. These ribbons can buckle spontaneously to form helical shapes, featuring regions of alternating chirality (phases) that are separated by so-called perversions (phase boundaries). This instability cannot be described by classical rod theory, which incorporates pre-stress through effective natural curvature and twist; these are both zero due to the mirror symmetry of the pre-stress. Using dimension reduction, we derive a one-dimensional (1D) ‘rod-like’ model from a plate theory, which accounts for inhomogeneous pre-stress as well as finite rotations. The 1D model successfully captures the qualitative features of torsional buckling under a prescribed end-to-end displacement and rotation, including the co-existence of buckled phases possessing opposite twist, and is in good quantitative agreement with the results of numerical (finite-element) simulations and model experiments on elastomeric samples. Our model system provides a macroscopic analog of phase separation and pressure–volume–temperature state diagrams, as described by the classical thermodynamic theory of phase transitions.

Analysis of Different Multiobjective Optimization Scenarios in Estimating the Adjustable Parameters of a Generalized Cubic Equation of State

Since the emergence of the van der Waals model, a lot of equations of state have been proposed to represent the pressure-volume-temperature (PVT) behavior of pure compounds, as is the case with GEOS3C, which is a form of generalized cubic equation of state that uses a temperature function dependent on three adjustable parameters. As the predictive capacity of an equation of state is directly related to the use of adequate and efficient methods for estimating the model's parameters, it is advised to use the multiobjective optimization in this class of problems, due to the conflicting nature of the objective functions. In this context, a MOPSO algorithm, based on the Pareto dominance principle, is used to estimate the parameters of the GEOS3C, through the minimization of the deviations in the prediction of different thermodynamic properties: saturation pressure, saturated liquid volume, enthalpy of vaporization and isobaric heat capacity, in order to assess whether it is possible to obtain a model parameterization that is adequate to represent the different properties simultaneously. Comparisons with experimental data available in the literature are performed showing that multiobjective optimization offers new perspectives for improvements in the parameters estimation of equations of state compared to traditional methods.

Kinetics of CO[formula omitted] dissolution for underground applications

In the current energy transition context, underground storage of carbon dioxide (CO2) in salt caverns and aquifers has emerged as a promising solution for the Power-to-Gas process complications. However, mass exchange between the CO2 and the aqueous phase present in the storage site remains a major problem. This paper addresses the question of the kinetics of this mass exchange by performing both experimental and numerical investigations. A series of experiments under storage conditions were carried out in a PVT (Pressure–Volume–Temperature) cell, exposing a volume of CO2 to pure water or brine at low and high pressure values ranging between 10 and 16.8 MPa and at constant temperatures of 30 and 40 °C. In order to interpret the obtained experimental results and to characterize the transient mass exchange, two modeling approaches were developed: a simplified one based on pure diffusion, and a second combining pure diffusion with density-driven natural convection. Both modeling approaches have proven accurate in predicting the kinetics of CO2 dissolution. The scope of this study is limited to the laboratory scale but it can be used to quantify the CO2 dissolution on the storage site scale.

Maximization of Gas-Oil Separation Plant Oil Recovery by Operation Parameter Optimization

Summary Maximizing oil recovery of the gas-oil separation plant (GOSP) is intended to increase revenue in the oil and gas industry. The GOSP is an integral part of the petroleum industry, and it consists of multistage separators, a heater-treater, desalination, a stabilization column, and a stock tank of oil. It is conventional practice to operate the GOSP at fixed operating conditions without considering the effects of variation for different parameters such as ambient temperature, chemical composition, reboiler (60°C, 65°C, and 70°C), and stabilization (temperature and pressure). Optimizing the GOSP parameters can help to maximize the GOSP oil recovery and, as a result, increase the revenue and profit. This study aims to optimize operation parameters to maximize the oil recovery of the GOSP at which the maximum oil recovery can be obtained from the GOSP. To achieve the objective of this study, first, a GOSP model was built using Petro-SIM process simulator software for a typical Saudi Aramco GOSP. The input data for the process simulator were the data from the initial pressure/volume/temperature (PVT) analysis. Optimizer tools in Petro-SIM were used to estimate the optimal conditions of the GOSP for achieving maximum oil recovery. The results showed that the optimization of the GOSP parameters such as ambient temperature, high-pressure separator (HPS), low-pressure separator (LPS), reboiler temperature, and stabilization pressure and temperature have a significant effect on the GOSP oil recovery and lead to increased revenues. Adjusting the HPS and LPS pressures to the optimal values at each ambient temperature significantly improves the GOSP oil recovery and can generate extra revenue of more than USD 500 million for 3 months considering the typical climate condition and GOSP (50,000 B/D capacity) in Saudi Arabia.

Mathematical Modelling of a Propellent Gauging System: A Case Study on PRISMA

Propellant gauging is crucial for a spacecraft approaching the end of its lifespan. Current gauging systems for satellites typically have an accuracy rate of a few months to a year at the end of their operational life. Therefore, it is essential to determine the appropriate gauging system for mission operations. This research focuses on modeling the propellant gauging system for PRISMA, an Earth Observation (EO) satellite of the Italian Space Agency. The analysis centers on implementing algorithms that calibrate the remaining propellant mass in the satellite tank using traditional methods such as bookkeeping (BKP) and pressure-volume-temperature (PVT). To enhance accuracy in quantification, an unconventional approach called thermal propellant gauging (TPG) has been considered. Preliminary computations were conducted using data obtained from the PRISMA thermal model to understand the calibration accuracy of the three methods. At the end of its operational life, the BKP and PVT methods exhibited error rates of 4.6% and 4.8%, respectively, in calculating the mass. In contrast, the TPG method demonstrated a significantly higher precision with an error rate of 1.86%. However, at the beginning of the satellite’s operational life, the PVT and TPG methods showed error rates of 1.0% and 1.3%, respectively, while the BKP technique reported an error rate of 0.1%. Based on these findings, it has been concluded that combining the BKP and TPG approaches yields superior results throughout the satellite’s lifespan. Furthermore, the researchers have determined the specific time duration for which each of these distinct approaches can be effectively utilized.

High pressure air injection in ultra-low permeability reservoirs: Effects of physical and chemical reactions on oil recovery

This research aims to investigate the effects of physical and chemical reactions on oil recovery during high-pressure air injection (HPAI) in ultra-low permeability reservoirs. The oxidation reaction characteristics of dead oil were investigated using thermal analysis experiments and oxidation tube experiments. Additionally, pressure-volume-temperature (PVT) analysis was employed to simulate the physical and chemical reactions between air and live oil under formation conditions. The results indicated that the fuel deposition (FD) stage exhibited less prominence in light oil due to its lower content of resins and asphaltenes. Additionally, the presence of cuttings impeded the volatilization of lighter components during low-temperature oxidation (LTO) stage, effectively storing fuel required for subsequent high-temperature oxidation (HTO) stage, consequently facilitating a direct transition from LTO to HTO. Notably, the debris derived from the ultra-low permeability reservoirs possesses an enlarged specific surface area, facilitating enhanced contact between the oil and oxygen. This heightened contact effectively reduces the activation energy required for the LTO stage by an appreciable 22.9 kJ/mol. Furthermore, the PVT experiments reveals a quadratic relationship between pressure and viscosity, while a cubic relationship exists between pressure and the expansion rate of crude oil. Moreover, the thermal effects of oxidation reactions and the dissolution of the gas phase have been found to exert a more substantial influence on reducing oil viscosity, in contrast to the oxygen addition reaction and the extraction of lighter components, which have a minor influence on increasing oil viscosity. Lastly, in the context of developing HPAI techniques for ultra-low permeability reservoirs, optimizing the gas injection rate emerges as a viable strategy to effectively enhance oil recovery, provided that the occurrence of gas channeling is effectively mitigated.

In situ single-crystal X-ray diffraction of olivine inclusion in diamond from Shandong, China: implications for the depth of diamond formation

Abstract. We have investigated a suite of natural diamonds from the kimberlite pipe of the Changma Kimberlite Belt, Mengyin County, Shandong Province, China, with the aim of constraining pressures and temperatures of formation. Here we report the non-destructive investigation of an olivine inclusion still entrapped within a lithospheric diamond by single-crystal X-ray diffraction. We were able to refine anisotropically its crystal structure to R1= 1.42 % using ionized scattering curves; this allows estimation of the composition of the olivine as Mg1.82Fe0.18SiO4. This composition corresponds to a calculated unit-cell volume equal to V= 292.70 Å3 at room temperature and pressure. We have validated the above-calculated composition and unit-cell volume by releasing the inclusion from the diamond host, resulting in a consistent composition calculated using non-destructive methods of Mg1.84Fe0.16SiO4 and V= 292.80 ± 0.07 Å3. Considering that the unit-cell volume of the olivine still inside its diamond host is V= 289.7 ± 0.2 Å3, we calculated a residual pressure Pinc= 1.4 ± 0.1 GPa with respect to the released crystal and Pinc= 1.3 ± 0.2 GPa with respect to the volume calculated from the “composition” indirectly retrieved by the structure refinement under ambient conditions. The two values of Pinc overlap within experimental uncertainty. We performed Fourier transform infrared (FTIR) analysis on the diamond host in order to calculate its mantle residence temperature, Tres, which resulted in a value of 1189 ∘C (for an assumed diamond age of 3 Ga) and 1218 ∘C (for an age of 1 Ga), with an average Tres equal to 1204 ± 15 ∘C. Using the most up-to-date pressure–volume–temperature equations of state for olivine and diamond, the residual pressure Pinc= 1.4 ± 0.1 GPa and average residence temperature of the diamond host Tres= 1204 ∘C, we retrieved a pressure of entrapment Ptrap= 6.3 ± 0.4 GPa. Using the non-destructive approach and relative Pinc = 1.3 GPa, we obtained a perfectly overlapping Ptrap= 6.2 GPa, within experimental uncertainty. This entrapment pressure corresponds to depths of about 190 ± 12 km. These results demonstrate that for high-quality crystal structure data measured on inclusions still trapped within diamond hosts, even a non-destructive approach can be used to calculate the depth of formation of diamond–olivine pairs. In terms of geological implications, the results from this work show that Changma diamonds formed under a conductive geotherm lying between 35 and 40 mW m−2, at a depth of about 190 km. This value lies within the recently reported upper limit of the average depth of formation of worldwide lithospheric diamonds, which is 175 ± 15 km and is in agreement with P–T data obtained in the literature from kimberlite xenoliths.

Empirical Determination of the Helmholtz Free Energy and the Gibbs Free Energy of Polyethylene Based on the Pressure–Volume–Temperature–Entropy Equation of State and the Partition Function

The Helmholtz free energy, A, and the Gibbs free energy, G, of polyethylene (PE) were determined based on its empirical pressure–volume–temperature–entropy equation of state, P-V-T-S Eos, and the empirical partition function, which we reported previously. The PA-VA-TA-SA Eos for the iso-Helmholtz free energy, iso-A, was determined based on the P-V-T-S Eos where the pressure (PA ), volume (VA ), temperature (TA ), and entropy (SA ) satisfied the condition that A is constant. The PG-VG-TG-SG Eos for the G being constant was also determined based on the P-V-T-S Eos. The three-dimensional (3D) plots, 3D plot, with the three axes, x = TA, y = PA, z = VA expressed by the 3D (TA , PA , VA ) and the 3D (TA, VA , SA ) at constant A in PE were determined, where the iso-A processes were characterized assuming that the volume and the entropy in the iso-A process decreased with increasing pressure and temperature, while in the 3D (TG, PG , VG ) and 3D (TG, VG , SG ) plots at constant G in PE, the volume and the entropy in the iso-G process were increasing with increasing pressure and temperature. The empirical partition function for the Helmholtz free energy was expressed by the summation of the terms of T, T 2, and T 4 , the Boltzmann factors with i = 1, 2, 3, and 6 and and the U(V,T = 0 K) term for the zero Kelvin internal energy where the T 4 term and the Boltzmann factors with i = 6 and 3 were dominant negative factors in the A-T relation at the constant V = 1.04 cm3/g. In case of the Gibbs free energy where the partition function was expressed by the summation of the terms of T, T 2, and T 4 , the Boltzmann factors with i = 1, 2, 3, and 6, the U(V,T = 0 K) term, PV and PV(T = 0) terms, the T2 term and the Boltzmann factors with i = 6 and 3 were dominant negative factors in the G-T relation at 1 atm (1.01 × 10−4 GPa), while at high pressure, 1.0 GPa, the PV and PV(T = 0) terms were dominant positive factors.

A novel technique for quantifying the fate of CO2 injected in oil reservoir for geological utilization and storage

CO2-enhanced oil recovery (CO2-EOR) is a potential CO2 capture, utilization, and storage technology. In particular, CO2 can break the hydrochemical balance of water–rock and converts into carbonate minerals which are the most stable sequestration phase. The water–rock reactions are complex kinetic processes because the rate of dissolution/precipitation of minerals are vary with the pH of the formation water. However, studies on the effect of geochemical reactions on CO2-EOR processes are lacking, and the fate of CO2 cannot be accurately quantified. In this study, we combine the characteristics of the oil phase into the thermal–hydraulic–chemical TOUGHREACT simulator to consider various water–rock geochemical kinetic reactions in CO2-EOR. Therefore, the distribution phase of CO2 can be determined completely in the reservoir. Our analyses use the realistic fluid property (pressure–volume–temperature) of multicomponent oil phase–CO2 mixtures. The model considers the possible geochemical reactions and the resulting changes in porosity and permeability. The results indicate that in gas–water cycle of 9% hydrocarbon pore volume CO2 slug, the largest distributed phase of CO2 is the gas phase, accounting for 52.2% during the CO2 injection period. After water injection, the solubility of CO2 in the oil phase increases, and CO2 is mostly dissolved in the oil phase, accounting for 53.0%. Without considering the water–rock geochemical reactions will result in an underestimation of the dissolved aqueous phase and correspondingly the others were overestimated. The maximum error of the distributed quantity is up to 6.4% of the total injection. In addition, the omission of water–rock reactions result in an underestimation of the oil recovery. Comparing with the CO2 storage in a saline aquifer, dissolution of CO2 in oil phase in CO2-EOR scenario dampens the effect of buoyancy, which leads to higher sequestration capacity for the same footprint of storage reservoir.

Evaluation of compositional models and PVT correlations for Iraqi light crude oils properties

AbstractEvaluation of common compositional models and pressure–volume–temperature (PVT) correlations are carried out against field data for light crude oil from north Iraqi reservoirs. The reported data and the evaluation are significant to the petroleum industry, as various international and local oil companies operate in this region. The comprehensive PVT program Multiflash™ 7.2 is utilized, employing the Peng–Robinson (PR) and Redlich–Kwong–Soave (RKS). The oil formation volume factor, bubble point pressure, solution gas–oil ratio (Rso), and saturated oil viscosity are chosen for this evaluation. The results demonstrate that the PR and RKS compositional models, with some adjustments, exhibit much higher accuracy as compared to PVT correlations. For example, the errors between the model's predictions and the field data for the Rso are 9% for PR ad 17% for the RKS model. In contrast, for the PVT correlations, much higher errors are obtained. The lowest errors (32%) are obtained with the Ikiensikimama and Ajienka, while above 90% errors (the highest) are reported by Petrosky and Farshad. This study will enable the petroleum industry to improve and optimize the production operations in north Iraq–Kurdistan region.

Equation of state of MgO up to 345 GPa and 8500 K

The accurate equation of state (EOS) of MgO can be used as a pressure scale, but the EOS currently used has too much uncertainty to serve as a pressure scale, especially at high-pressure and high-temperature conditions. Here we present a complete EOS of solid MgO up to 345 GPa, 8500 K, and its derived pressure-volume-temperature (P-V-T) EOS form, which can be used as a pressure scale. In this EOS, the free energy is expressed as a three-parameter function based on a quasi-Debye thermodynamic model, which establishes a relatively accurate phonon thermodynamic description by determining the phonon dispersion relation and phonon density of states from the volume-dependent sound velocity. The three parameters are determined by a global optimization method, which minimizes the sum of the weighted variances between the physical quantities calculated by the thermodynamic model and the relevant experimental values within the unified EOS framework. To improve the accuracy of the EOS, the parameters are constrained by room-temperature sound velocities and shock compression data, including P-V-T data and sound velocities up to 265 GPa along the principal Hugoniot of MgO measured by us, the P-V-T data at 174--203 GPa, and partial P-V-T data of MgO preheated to 1850 K by others. The derived EOS of MgO can well reproduce not only the above data used to define the parameters, but also the shock compression data and the measured isobaric specific heat not used in the parameter optimization.