PVT Tests Research Articles

Solvent Exsolution and Liberation from Different Heavy Oil–Solvent Systems in Bulk Phases and Porous Media: A Comparison Study

In this paper, experimental and numerical studies were conducted to differentiate solvent exsolution and liberation processes from different heavy oil–solvent systems in bulk phases and porous media. Experimentally, two series of constant-composition-expansion (CCE) tests in a PVT cell and differential fluid production (DFP) tests in a sandpacked model were performed and compared in the heavy oil–CO2, heavy oil–CH4, and heavy oil–C3H8 systems. The experimental results showed that the solvent exsolution from each heavy oil–solvent system in the porous media occurred at a higher pressure. The measured bubble-nucleation pressures (Pn) of the heavy oil–CO2 system, heavy oil–CH4 system, and heavy oil–C3H8 system in the porous media were 0.24 MPa, 0.90 MPa, and 0.02 MPa higher than those in the bulk phases, respectively. In addition, the nucleation of CH4 bubbles was found to be more instantaneous than that of CO2 or C3H8 bubbles. Numerically, a robust kinetic reaction model in the commercial CMG-STARS module was utilized to simulate the gas exsolution and liberation processes of the CCE and DFP tests. The respective reaction frequency factors for gas exsolution (rffe) and liberation (rffl) were obtained in the numerical simulations. Higher values of rffe were found for the tests in the porous media in comparison with those in the bulk phases, suggesting that the presence of the porous media facilitated the gas exsolution. The magnitudes of rffe for the three different heavy oil–solvent systems followed the order of CO2 > CH4 > C3H8 in the bulk phases and CH4 > CO2 > C3H8 in the porous media. Hence, CO2 was exsolved from the heavy oil most readily in the bulk phases, whereas CH4 was exsolved from the heavy oil most easily in the porous media. Among the three solvents, CH4 was also found most difficult to be liberated from the heavy oil in the DFP test with the lowest rffl of 0.00019 min−1. This study indicates that foamy-oil evolution processes in the heavy oil reservoirs are rather different from those observed from the bulk-phase tests, such as the PVT tests.

Utility of the psychomotor vigilance task in screening for obstructive sleep apnoea.

The study aimed to assess the performance of the PVT in patients with suspected OSA, evaluate its role in population screening for OSA. The NoSAS, STOP-Bang, ESS scores and PVT tests were performed after suspected OSA patients' admission, followed by PSG. Then we compared the PVT results, calculated the sensitivity, specificity and ROC curve of PVT, and analyzed the accuracy of STOP-Bang and NoSAS questionnaire combined with PVT in predicting OSA. A total of 308 patients were divided into four groups based on AHI: primary snoring (2.74 ± 1.4 events/h, n = 37); mild OSA (9.96 ± 3.25 events/h, n = 65); moderate OSA (22.41 ± 4.48 events/h, n = 76); and, severe OSA (59.42 ± 18.37 events/h, n = 130). There were significant differences in PVT lapses (p < 0.001) and reaction time (RT, p = 0.03) among the four groups. The PVT lapses and RT were positively correlated with AHI (p < 0.001) and ODI (p < 0.001), and negatively correlated with LSpO2 (p < 0.001). When diagnosing OSA (AHI ≥ 5 events/h), the AUCs of PVT, ESS, STOP-Bang, and NoSAS were 0.679, 0.579, 0.727, and 0.653, respectively; the AUCs of STOP-Bang and NoSAS combined with PVT increased. After combined PVT, the diagnostic specificity of STOP-Bang and NoSAS at nodes with AHI ≥ 5, ≥ 15 and ≥ 30 events/h increased to varying degrees. Patients with OSA exhibited impairment in the PVT, and the combination of the PVT and STOP-Bang or NoSAS scores can improve the diagnostic efficacy and specificity for OSA.

Development of a new approach using an artificial neural network for estimating oil formation volume factor at bubble point pressure of Egyptian crude oil

Understanding the phase behavior and volumetric changes of reservoir fluids throughout the extent of reservoir lifetime are crucially required for effective-commercial oil recoveries. Ideally, reservoir fluid properties are experimentally measured by laboratory experiments known as PVT tests nonetheless, these tests are prohibitive, time-consuming, and required to restrict sampling and transporting procedures. For these discernible reasons, several modeling approaches have been developed. By reviewing the literature, one crucial obstacle that encounters field applicability of most extant models is the selection of input variables. Moreover, a great percentage of extant models employ the results of lengthy experimental tests such as differential gas solubility or even the sample’s chemical composition. Replicability of models’ results using different datasets is also one of the main challenges when employing AI models. Frequently, inadequate descriptions for AI models have been provided in many studies which limits their utility. The inadequate description includes the analysis of ANN model weights and biases besides, the final mathematical model. In this study, a rigorous ANN model with its mathematical model has been implemented to predict oil formation volume factors based on 600 compiled datasets from Egyptian oilfields.A detailed comparison between widely used empirical correlations and the proposed new ANN model is provided in this study. Statistical and graphical analysis depicted the outstanding performance of the new model with R2 = 0.974, ARE = −0.0017%, and AARE = 2.13%. The ANN model provides remarkable sustainable performance compared to local Egyptian empirical correlations and all the other global models.

Geraniol enhances inhibitory inputs to the paraventricular thalamic nucleus and induces sedation in mice

BackgroundPlant extracts with sedative effects have a long history of clinical use for treating insomnia and epilepsy. Geraniol (GE), a plant-derived acyclic monoterpene, reduces locomotion and prolongs barbiturate-induced anesthesia in rats. However, the mechanisms of GE in sedation remain elusive. PurposeThis study aimed to investigate the mechanisms of GE in sedation in mice. MethodsGE was administered systemically by nebulization and intraperitoneal injection. Open field tests, acute seizure tests, and electroencephalogram (EEG) recordings were performed to examine the sedative effects of GE in mice. The time of loss of the righting reflex and return of the righting reflex were recorded in anesthesia experiments to examine the effect of GE on anesthesia. In vitro c-Fos staining and in vivo fiber photometry recordings were performed to detect the activity change of the paraventricular thalamic nucleus (PVT). Microinjection of GE into PVT and related behavioral tests were performed to confirm that PVT was a critical target for GE. Whole-cell recordings were performed to dissect the effects of GE on PVT neurons via GABAA receptors. Molecular docking was performed to examine the interaction between GE and GABAA receptor subunits. ResultsWe found that GE reduced locomotion, relieved acute seizures, altered the EEG, and facilitated general anesthesia in mice. Next, we found that GE decreased c-Fos expression and suppressed the calcium activity in PVT. Microinjection of GE into PVT reduced locomotion and facilitated anesthesia. Furthermore, electrophysiology results showed that GE induced dramatic membrane hyperpolarization and suppressed the activity of PVT neurons, mainly by prolonging spontaneous inhibitory postsynaptic currents and inducing tonic inhibitory currents. Molecular docking results indicated that the β3 subunit might be a potential target for GE. ConclusionBy combined using behavioral tests, immunohistochemistry, calcium recording, and electrophysiology, we systematically revealed that GE inhibits PVT and induces sedation in mice. Essential oils have long been considered part of traditional medicine, and they are playing a critical role in aromatherapy. Since GE has a comparatively ideal safety property and multiple delivery methods, GE has great application potential in aromatherapy. Our study also provides a potential candidate for further development of sedatives and anaesthetics.

Human cognitive functions and psycho-physiological responses under low thermal conditions in a simulated office environment.

In office environments, thermal comfort is one of the most significant factor affecting employees' performance. This study aimed to determine the effects of exposure to low air temperatures on human cognitive performance, physiological responses, and thermal perceptions during mental work. Twenty-four volunteers with an age range of 18-30 years participated in this study. The subjects were exposed to four different air temperatures (10, 14, 18, and 22°C) in a climate chamber based on a within-subject design. The n-back, CPT, and PVT tests were employed to evaluate some basic aspects of cognitive performance. Body physiological responses and the subjective thermal comfort were also measured. When the thermal condition deviated from relatively neutral temperature, the subjects' cognitive responses significantly disturbed (P < 0.05), such that the response accuracy was more affected by reduction of air temperature. The blood pressures and heart rate, galvanic skin response, and respiration rate increased as the air temperature decreased (P < 0.05), such that the galvanic skin response as a stress indicator was more affected. In the test configurations, as a result of decrease in air temperature of 1°C, the finger and body skin temperatures reduced to 0.74°C and 0.25°C, respectively. The findings confirmed that low thermal condition can considerably affect cognitive performance and physiological responses during some office work tasks. The subjects' thermal comfort votes proposed that air temperature lower than 14 °C can be intolerable for employees during routine mental work. It is suggested that personalized conditioning systems should be used to provide individual thermal comfort in moderate cold air conditions.

New Correlation of Oil Compressibility at Pressures Below Bubble Point For Iraqi Crude Oil

Oil compressibility represents a significant character in reservoir simulation, design of surface facilities and the analysis of well tests, specifically for systems below the bubble point pressure. Oil compressibility is not directly measured in the laboratory. It is usually gained indirectly from experimental data recorded in PVT reports. The relative volume from the flash test is used to calculate oil compressibility at pressures above the bubble point pressure. At pressures below the bubble point, the reservoir behavior is simulated by the differential liberation test. The solution gas-oil ratio and the oil formation volume factor from the differential liberation test are employed in the estimation of oil compressibility at pressures below the bubble point pressure This paper purposes new correlation for calculating isothermal oil compressibility coefficient at and below bubble point pressure. The formulation of oil compressibility correlation is very difficult as it depends on many variables. This property is a function of many variables such as bubble point pressure, reservoir pressure, reservoir temperature, solution gas-oil ratio, oil formation volume factor, stock-tank oil gravity, specific gravity of gas and gas formation volume factor. Standing’s (1), McCain et al. (2) and Al-Jarri's (3) correlations were submitted for testing their validity to evaluate their performance with Iraqi crude oils and to compare their results with the results of the new correlation. The achievement of the new correlations has been done using two hundreds and nine data points from twenty PVT tests that were collected from Southern Iraqi fields. The evaluation of the previous correlations has achieved with graphical and statistical methods. These checking methods show a poor agreement between the observed and the calculated values. The checking methods (graphical and statistical) explain that the new correlation that was achieved in this paper is suitable to calculate oil compressibility below bubble point pressure for Iraqi crude oils.

Determination of Minimum Miscibility Pressure (MMP) using PVTi Software, Eclipse 300 and Empirical Correlations

One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together to form a single phase. This pressure is typically abbreviated as MMP. Among the available methods for determining the minimum miscibility pressure, laboratory methods including slim tube test and ascending bubble apparatus test are more widely utilized. Although the mentioned tests have high measurement accuracy, they are very time consuming and expensive. Therefore, the determination of the minimum miscibility pressure is usually done using computational and simulation approaches that also have high accuracy. Conducting PVT tests and determining their MMP using slim tube method was previously performed. In this study, the minimum miscibility pressure of reservoirs was determined by applying three methods of simulation with PVTi software, simulation with Eclipse 300 software and using Empirical Correlations. By comparing the obtained results and the laboratory results, it was revealed that the simulation by Eclipse 300 is regarded as the fastest and most accurate approach.

Performance and mechanisms of enhanced oil recovery via CO2 assisted steam flooding technique in high heterogeneity heavy oil reservoir: PVT and 3D experimental studies

In this paper, CO2 assisted steam flooding technique was proposed to further enhance heavy oil recovery after steam flooding. PVT tests and 3D model oil displacing experiment were conducted to investigate enhancing oil recovery (EOR) mechanisms and oil displacing performance. The results indicated that CO2 dissolving in heavy oil could induce oil swelling, reduce oil relative density, and reduce oil viscosity. After steam flooding, 6.8% of sweep efficiency and 8.5% of additional oil recovery were improved by implementing CO2 assisted steam flooding. The study has suggested that CO2 assisted steam flooding is a feasible technique for recovering heavy oil after steam flooding.HighlightsCO2 dissolving heavy oil can swell oil volume and reduce oil viscosity dramatically.CO2 alternative steam flooding can improve injection pressure and oil–steam ratio, and reduce steam consumption.Introducing CO2 into steam flooding process can increase both oil displacement efficiency and sweep efficiency, then enhancing oil recovery.CO2 assisted steam flooding is a feasible technique for improving oil recovery in heavy oil reservoir after steam flooding.

A novel visualization approach for foamy oil non-equilibrium phase behavior study of solvent/live heavy oil systems

In this study, a novel visualization methodology to study solvent non-equilibrium exsolution behavior in heavy oil systems is proposed. A Hele-Shaw-like visual cell with adjustable aperture depth, has been designed to overcome the shortcomings of traditional apparatuses such as a hardly-visual PVT cell, or non-visual transfer cylinders. By eliminating the 3D nature of the traditional apparatuses, the true 2D bulk phase visual cell can directly visualize the interface evolution of foamy oil under pressure depletion. Totally, 6 sets of Constant Composition Expansion tests (CCE) were conducted with a CO2-C3H8-heavy live oil system. The effect of pressure depletion rates on solvent non-equilibrium exsolution behavior have been tested. Meanwhile, the initial volume fill-up percentage of live oil in the visual cell was also found to have an effect on foamy oil generation and endurability. This helps to define the appropriate volume of live oil to be saturated in PVT tests that aim to induce non-equilibrium. Through analyzing the deviation of liquid/vapor phase volume fraction from equilibrium state, non-equilibrium regimes of solvent exsolution were effectively found. The experimental design is also able to continuously capture the real-time solvent component exsolution sequence during pressure depletion. Numerical simulation of solvent non-equilibrium exsolution behavior has been conducted by a MATLAB-controlled reservoir simulator with real-time optimization. By dynamically adjusting the K value in the simulator, the total flashed vapor phase volume and the individual solvent component mass was history-matched. The achieved non-equilibrium K values were compared with equilibrium K values, and a delayed solvent exsolution was indicated.

Experimental study on foamy oil flow behavior of a heavy oil-N2 system under reservoir condition

For heavy reservoirs, conventional oil recovery methods are polymer flooding and Steam-assisted Gravity Drainage (SAGD). Such methods are affected by various factors including reservoir thickness, formation heterogeneity, heat loss, and cost, especially in deep heavy oil reservoirs. In these deep reservoirs, their crude oil has a viscosity in the tens of thousands of centipoises at surface conditions, but only a few hundred centipoises at high temperature. There is sufficient mobility of crude oil making it possible for nitrogen (N2) huff-n-puff to be applied. Since foamy oil is a very significant production mechanism in huff-n-puff process, this study is to confirm the ability of nitrogen to form foamy oil in a deep heavy oil reservoir.This study includes two types of tests. The first category is the PVT tests to measure N2 solubility in heavy oil. It was found that the solubility of nitrogen in the oil sample at 50 °C and 7 MPa is 7.54 m3/m3. The second category is the pressure depletion tests conducted in a 1-D cylindrical model to observe the flow behavior. These tests are conducted consistently at four different pressure decline rates. It confirmed the possibility of foamy oil formed by nitrogen and summarized the variation of the flow pattern.This research is a preliminary basic study of N2 huff-n-puff in heavy oil reservoirs. Confirmation of the technology’s feasibility will significantly reduce the cost of exploiting heavy oil reservoir.

Testing the injection of air with methane as a new approach to reduce the cost of cold heavy oil recovery: An experimental analysis to determine optimal application conditions

We propose a new approach to reduce the associated cost of CSI (cyclic solvent injection) by using air with methane to pressurize the reservoir and improve the foaminess process. This reduces the cost as the amount of methane injected is curtailed, but the process needs to be optimized by determining the optimal application conditions by maximizing final heavy oil recovery. To study the use of air for a technical and economic improvement of CSI with methane, pressure depletion tests were performed at a pressure depletion rate of −0.51 psi/min in a cylindrical sandpack, placed in a 150 cm long and 5 cm diameter sandpack holder supplied with eight evenly distributed pressure transducers and three thermocouples. Production profiles (pressure at every port, pressure differences, and pressure gradient) and saturation distributions were studied to determine the conditions yielding the best sweep and the highest oil and gas recovery factor with minimal use of gas injected. Different injection/production schemes (alternate or co-injection of an air-methane pair and different injector-producer alignments), depletion rates, and soaking times were tested to determine the conditions to maximize the recovery factor. Furthermore, observational experiments at a macroscopic and microscopic scale after the PVT tests were performed by recombining the heavy oil sample with sole air, sole methane, and a mixture of air and methane at a volume ratio of 1. Using a mixture of air and methane not only expanded the volume of oil (gas bubbles trapped into the oil) by 2.5 but also delayed the defoaming process at both macroscopic and microscopic scales. Numerous tiny gas bubbles were initially observed, which kept its size and number for more time than the methane case, which is an indication of restraining fast bubble growth and subsequent coalescence. The best injection strategy for a single-well injection scheme was the simultaneous injection of air and methane on a soaking period of 2–3 days, whereas for a multi-well injection scheme an alternating injection strategy on a soaking period of 4–5 days offered the best performance. Cumulative oil and gas recovery factors were as high as 27.46% and 76.68%, respectively, when air was accompanied by methane. Using air as a foamy oil ameliorative was observed to save up to 26% on methane use in single-well injection schemes and up to 51% on multi-well injection schemes.

Three different periods of CO2 dissolution into a light crude oil

ABSTRACTIn this paper, phase behaviours and mass‐transfer mechanisms of a Bakken light crude oil‐CO2 system are studied. A series of PVT tests of the light crude oil‐CO2 system are conducted to measure CO2 solubilities, oil‐swelling factors, and CO2‐saturated oil densities at different equilibrium pressures and the actual reservoir temperature of Tres = 56.0 °C. Five CO2 diffusion tests in the light crude oil are performed at five different initial test pressures (Pi = 4.1, 5.2, 6.3, 7.7, and 9.0 MPa) and Tres = 56.0 °C by applying the pressure decay method (PDM). The graphical method (GM) is used to analyze the measured test pressure versus time data of each diffusion test and determine CO2 average diffusivity in the light crude oil. It is found that the so‐called density‐driven natural convection can occur in the CO2‐saturated light crude oil as its measured density is much higher than that of the dead light crude oil. Three distinct periods of CO2 dissolution into the light crude oil are identified: the natural convection‐dominated period (I), the transition period, and the molecular diffusion‐dominated period (II). The determined CO2 effective diffusivities (Deff) in Period I and CO2 molecular diffusivities (D) in Period II from the GM are in the ranges of 0.28–1.75 × 10−6 m2/s and 0.87–1.94 × 10−9 m2/s at the initial test pressures of Pi = 4.1–9.0 MPa, respectively. Finally, it is also found that the constant Z‐factor approximation used in the GM may cause a relatively large error in the determination of Deff or D.

A new approach to characterize the performance of heavy oil recovery due to various gas injection

The performance of CO2 injection into a semi-heavy oil reservoir was investigated at reservoir conditions, using highly permeable sandstone in a complete series of PVT tests and coreflooding experiments. Analysis of involved parameters such as: injection rate, injectant type and reservoir pressure were also considered. Oil viscosity reduction and oil swelling are the most influential mechanisms of enhanced oil recovery in this process. The results demonstrated that CO2 injection would decrease the interfacial tension for the high permeable medium in the absence of capillarity, but this reduction may not improve the recovery drastically. One of the main important aspects of this work is the introduction of a new empirical combined dimensionless group (dissolution number, Ndis) that helps prediction of oil recovery in any other heavy oil reservoir with high permeability of porous media. In this case, a more precise analysis could be performed by applying the dissolution number instead of capillary and/or Bond number.

Study on equilibrium and non-equilibrium PVT behavior of foamy oil using experiments and PVT correlations

The traditional understanding of PVT behavior of conventional oil is rather different under foamy oil condition. This paper focuses on the PVT tests with Venezuela heavy oil, and development of a new methodology for equilibrium and non-equilibrium PVT properties of foamy oil. Firstly, the study involved PVT tests to reveal the equilibrium and non-equilibrium PVT properties of foamy oil. Then, in order to give the best equilibrium PVT correlations for field applications, some classic equilibrium PVT correlations were tested against the experimental data with strong foamy oil tendencies. Finally, several functional relationships were developed to describe the time effects on non-conventional PVT properties of foamy oil by fitting the experimental results. Then, a set of models for non-equilibrium PVT properties were proposed and validated with experimental data in literature. The results show that, for the measured crude oil, a higher depletion rate leads to a lower pseudo bubble point pressure and higher oil compressibility, indicating a stronger tendency for foamy oil occurrence. The foamy oil exhibits stable solution GOR, high formation volume factor, low oil density and slightly low oil viscosity below bubble point pressure. The selected and developed equilibrium PVT correlations have a wide scope of application and high precision. A comparison of the estimated and experimental PVT data show differences of 6.55% for solution GOR, 9.05% for oil compressibility, 0.84% for oil FVF, 4.5% for oil viscosity and 0.46% for oil density. The proposed non-equilibrium PVT models for the foamy oils provide average error of 7.07% for solution GOR, 16.07% for oil compressibility, 0.73 for oil FVF and 10.68% for oil viscosity and 0.63% for oil density. Application of this developed methodology can avoid the accomplishment of conventional and non-conventional PVT tests.

PVT behavior of methane and ester-based drilling emulsions

Abstract Well construction is especially complex in deep and ultra-deep water, where large Brazilian oil and gas reserves are located, demanding the use of synthetic-based drilling fluids, which have adequate characteristics such as lubricity, shale stabilization and low toxicity. Hydrocarbon gas kick will dissolve to some extent in any drilling fluid, but this effect can generally be ignored with a water-based drilling fluid. However, an operator working with synthetic-based drilling fluid must have training in gas solubility to avoid a blowout situation. Methane is the main component of natural gas, while ester can be used in the formulation of synthetic drilling fluids. To study phase equilibrium of these gas–liquid mixtures, at high pressures and high temperatures, found in bottom-hole conditions, specific, work and time intensive experimental tests were performed. The objective of this work is to present the experimental PVT data obtained from methane and ester emulsion mixtures. The fluid was loaded into a PVT cell and tests were carried out at desired conditions. Gas enrichment procedure was devised to cover temperature, pressure and methane concentration range with a long-term, single liquid amount test. Thermodynamic properties such as bubble pressure, solubility, density and formation volume factor of these mixtures were calculated up to 103 MPa and 130 °C, similar to bottom-hole conditions. A model based on the Peng–Robinson equation of state was used to predict the bubble point of the mixture.

Rheological methods to investigate graphene/amorphous polyamide nanocomposites: Aspect ratio, processing, and crystallization

Nanocomposites obtained by melt mixing commercial graphene in an amorphous polyamide are investigated. No symptoms of percolation are observed, which is attributed to the low aspect ratio (fs = 20) deduced from elastic modulus data. The study of the effect of temperature and pressure on viscosity, carried out combining extrusion rheometry and PVT tests, reveals that the nanocomposites can be extruded and injected under similar conditions to pure polyamide. The time evolution of the dynamic viscoelastic functions are analyzed to investigate the crystallization process, observing that it is considerably accelerated in nanocomposites. The results represent a valuable outcome for practical applications. POLYM. ENG. SCI., 55:1142–1151, 2015. © 2014 Society of Plastics Engineers

Determination of Saturation Pressures and Swelling Factors of Solvent(s)–Heavy Oil Systems under Reservoir Conditions

Techniques have been developed to experimentally and theoretically determine saturation pressures and swelling factors of solvent(s)–heavy oil systems under reservoir conditions. Experimentally, PVT tests are performed to measure saturation pressures and swelling factors of a C3H8–heavy oil system and a CH4–C3H8–heavy oil system under reservoir conditions, respectively. Theoretically, the volume-translated Peng–Robinson equation of state (PR-EOS) together with the modified alpha function has been used to model phase behavior of the aforementioned solvent(s)–heavy oil systems. A binary interaction parameter (BIP) correlation has been developed for CH4–heavy oil systems based on the literature data. As for the CH4–C3H8–heavy oil system with a fixed composition, both saturation pressure and swelling factor increase with temperature. The PR-EOS together with the modified alpha function and the newly developed BIP correlation is able to predict the saturation pressures and swelling factors of the CH4–C3H8–heav...

Temperature effects on the phase behaviour, mutual interactions and oil recovery of a light crude oil–CO2 system

In this paper, the temperature effects on the phase behaviour, mutual interactions, and oil recovery of a light crude oil–CO2 system are experimentally studied. First, six PVT tests are performed to measure the saturation pressures and the oil-swelling factors of three light crude oil–CO2 systems with different CO2 concentrations. Second, a series of saturation tests are conducted to determine the onset pressure (Pasp) of asphaltene precipitation from the light crude oil–CO2 system. Third, the minimum miscibility pressure (MMP) and the first-contact miscibility pressure (Pmax) of the light crude oil–CO2 system are determined by applying the vanishing interfacial tension (VIT) technique. Meanwhile, the oil-swelling effect, the initial quick and subsequent slow light-hydrocarbons extraction phenomena are observed during the dynamic interfacial tension (IFT) measurements. In particular, the onset pressure (Pext) for the initial quick light-hydrocarbons extraction by CO2 is noted. Finally, a total of eleven CO2-coreflood tests are undertaken to examine the temperature effect on the CO2-based oil recovery. All the above-mentioned experiments are conducted at a laboratory temperature of Tlab=27.0°C and at the actual reservoir temperature of Tres=53.0°C, respectively. It is found that the test temperature has a strong effect on the saturation pressure but a marginal influence on the oil-swelling factor of a given light crude oil–CO2 system. It is also found that the four onset pressures are in the order of magnitude: Pasp<Pext<MMP<Pmax. Furthermore, Pasp and Pext increase slightly but the MMP and Pmax increase significantly with the test temperature. Lastly, a higher test temperature leads to a higher oil recovery factor as long as the CO2 flooding is miscible.

A Case Study on Foamy Oil Characteristics of the Orinoco Belt, Venezuela

With a current recovery of less than 11%, the Orinoco Belt in Venezuela still contains potentially more than 1.3 trillion barrels of reserves of “three highs, one low” oil at a depth of 100 to 1500 m. 5 joint projects and one project of Petroleos de Venezuela SA are making plans to improve oil recovery in the area. So it is important for them to have a thorough knowledge of foamy oil characteristics. This reservoir has a peculiar behavior called as a foamy phenomenon. In order to characterize the properties of the foamy oil, this paper discussed unconventional test methodology and the detailed suite of laboratory procedures including PVT and pressure depletion tests used to examine the Orinoco heavy oil. The results showed substantial differences in characteristics of foamy oil and conventional oil studied, not only in terms of PVT behavior but also in terms of the production performance during pressure depletion tests. The foamy oil compressibility was between 10-120×10 -4 mPa -1 , which was obviously higher than that of conventional oil. Differential liberation experiments of the oil, with obvious high formation volume factor, stable GOR, and low density showed a strong tendency to foam below the bubble point. Other notable observations were that more efficient oil recovery was achieved at high depletion rates while less free gas was produced. Key words : Foamy oil; Unconventional tests; The Orinoco Belt; PVT; Pressure depletion tests

Determination of Multiphase Boundaries and Swelling Factors of Solvent(s)–CO2–Heavy Oil Systems at High Pressures and Elevated Temperatures

A generalized methodology has been proposed and successfully applied to determine multiphase boundaries as well as swelling factors of solvent(s)–CO2–heavy oil systems at high pressures and elevated temperatures. Experimentally, two- and three-phase boundaries and swelling factors have been respectively measured by conducting PVT tests in the temperature range of 280.45 to 396.15 K. Theoretically, the Peng–Robinson equation of state (PR EOS) combined with the modified alpha function has been applied to describe phase behavior of the solvent(s)–CO2–heavy oil systems. More specifically, an exponential distribution function is used to split a heavy oil sample, whereas the logarithm-type lumping method is employed to group single carbon numbers (SCNs) into multiple carbon numbers (MCNs). The exponents associated with two binary interaction parameter (BIP) correlations are respectively tuned for the alkane solvent-pseudocomponent pair and CO2-pseudocomponent pair to match the measured saturation pressures. It is found that six pseudocomponents combined with the BIP correlation as a function of critical volume is sufficient to predict saturation pressure with an absolute average relative deviation (AARD) of 5.07%. In addition, the PR EOS model associated with the selected parameters is applied to predict three-phase boundaries for a C3H8–CO2–heavy oil mixture and a n-C4H10–CO2–heavy oil mixture yielding an overall AARD of 4.58%. As for swelling factors, the Peneloux et al. method provides the minimum AARD of 2.09% in comparison with 4.00% from the Jhaveri et al. method and 2.41% from the Twu et al. method, respectively.