Live Oil Research Articles

Theoretical and experimental investigation of effect of salinity and asphaltene on IFT of brine and live oil samples

Several factors influence the IFT of oil and formation water. These factors are rooted in the complex composition of oil, presence of different salts in water, water salinity, temperature, and pressure of reservoir. In the first part of this paper, effect of salinity on IFT between brine and an Iranian live oil sample has been studied experimentally. It is observed that IFT increases almost linearly with brine concentration. Also, linear increasing behavior of IFT with respect to pressure is obviously seen. Then, using thermodynamic properties such as surface excess concentration, chemical potential, chemical activity, and activity coefficient, results were analyzed and observed effect of salinity and pressure were justified thermodynamically. In the second part, the effect of asphaltene on IFT reduction has been studied. In previous works, the investigators extracted resin and asphaltene and then examined their effects on IFT in the absence of other fractions of oil phase. We believe that all fractions play a role in this phenomenon so, in this paper, the effect of natural surfactants of oil phase on IFT has been investigated in presence of all fractions of oil. Hence, SARA test was performed on all samples. Then, IFT between oil samples and brine were measured using captive drop instrument at 25 °C and 3000 psia. Results showed that neither asphaltene content nor asphaltene/resin ratio is a good indicator for effect of asphaltene on IFT, whereas colloidal instability index could be a useful tool to predict asphaltene effect on IFT.

A Wavelet-Based Model for Determining Asphaltene Onset Pressure

Asphaltene onset pressure (AOP) is a significant parameter for determining the flow assurance of live oils. The solid detection system (SDS) is one of the prevalent techniques used by service laboratories to evaluate the stability of asphaltenes under reservoir conditions. The determination of AOP based on this technique entails the interpretation of recorded data, making the accuracy of the result prone to error. Accordingly, this research aimed to provide a robust computational method for determining AOP by wavelet analysis of SDS data. Changes in the curvature of transmitted light (CTL) were considered a diagnostic criterion to detect AOP. To substantiate this hypothesis, CTL was first calculated at each pressure. The discrete wavelet transform was then applied to decompose the CTL curve and compute the CTL entropy $$\left( {E_{\text{CTL}} } \right)$$ based on the decomposition results. Finally, a relation was established between AOP and the entropy variations of CTL $$\left( {\Delta E_{\text{CTL}} } \right)$$ , leading to the AOP determination model. This model indicated that the maximum value of $$\Delta E_{\text{CTL}}$$ is at AOP. Put differently, the onset of asphaltene precipitation pressure corresponds to the highest variation in the CTL entropy. The results obtained from the AOP determination model in various reservoirs are consistent with the experimental findings.

Toward smart schemes for modeling CO2 solubility in crude oil: Application to carbon dioxide enhanced oil recovery

This paper presents an artificial intelligence-based numerical investigation on the CO2 solubility in live and dead oils for possible CO2-enhanced oil recovery (EOR). A thorough smart modeling was accomplished by utilizing Multilayer Perceptron (MLP) and Radial Basis Function (RBF) neural network predictors integrated with seven vigorous optimization algorithms. Furthermore, Group Method of Data Handling (GMDH) approach was manipulated to achieve explicit mathematical expressions for the scope of the current study. The modeling was performed on a rich source of data derived from the previously published works. Assessments regarding all extended models demonstrated the Absolute Average Relative Error (AARD) ranges of 1.19%–3.47% and 1.63%–3.13% for live and dead oils, respectively. This indicates the prosperousness of all suggested models for anticipating the CO2 solubility in live/dead oil. A comparison between the proposed models indicated the marginally better performance of the MLP-LM (AARD = 1.19%) and MLP-SCG (AARD = 1.63%) in the case of live and dead oils, respectively. Additionally, the implemented models were compared against various published approaches, and the results revealed that the majority of our newly generated models outperform the prior approaches. In addition, the established GMDH-derived correlations were found to be the most truthful in comparison to other explicit literature correlations. These results provide significant insights for understanding the complex physicochemical processes of CO2-EOR and accurately predicting CO2 solubility in live and dead oils in reservoirs.

Prediction of live reservoir fluid interfacial tension from dead oil measurements

The interfacial tension (IFT) between crude oil and water governs the multiphase flow in porous media and is therefore of paramount importance for understanding reservoir behavior. IFT data is commonly, but inadequately, acquired at ambient conditions using samples of dead oil, because live crude oil samples are limited in availability and measurements under high pressure and temperature conditions are complex. In this study, ten live crude oil samples were used to establish the first correlation allowing to predict live crude oil interfacial tension based on dead oil IFT values and conventional PVT data. IFT experiments were executed for all samples at different pressure and temperature conditions. A common trend of IFT increase from the dead oil at ambient to the live oil at reservoir conditions was noted in the experiments. Based on the measured data, a correlation was established to predict live oil IFT at reservoir conditions from dead oil IFT at ambient condition, using dead oil viscosity and molecular weight, as well as gas to oil ratio and fluid densities as input parameters. The correlation showed a strong coefficient of determination (R2 = 0.98) and was validated using three additional live crude oils from different fields. The IFT values at reservoir conditions were well predicted with average errors below 5%.

Impact of in-situ gas liberation for enhanced oil recovery and CO2 storage in liquid-rich shale reservoirs

ABSTRACT Carbon dioxide injection in shale reservoirs can be beneficial for enhanced oil recovery and CO2 storage scenarios. CO2 mass transfer can be influenced strongly by the in-situ liberation of light oil components from live oil forming a distinct gas phase. This mechanism has been overlooked in the past for studying CO2 and oil interactions in tight formations. In this work, a series of analytical solutions and numerical simulations were developed to identify the effect on EOR by CO2 due to the liberation of a light hydrocarbon gas phase from live oil in shales. The analytical model demonstrated faster diffusion of CO2 in the two-phase system due to the presence of this gas phase. Using numerical approaches, laboratory-scale simulations indicated that in-situ gas formation can increase oil recovery by 35%. At the field-scale, an additional oil recovery of 9.8% could be attained. Also, the CO2 storage capacity of shale formations could be significantly enhanced due to capillary trapping of CO2 in the liberated gas. The results of this study could potentially be used to improve evaluations of the potential of CO2 EOR in shale reservoirs.

Olive oil and risk of breast cancer: a systematic review and dose-response meta-analysis of observational studies.

Olive oil consumption has been suggested to be inversely associated with breast cancer risk, probably due to its high MUFA and polyphenol content. The purpose of this meta-analysis was to assess the association between olive oil and breast cancer risk, including assessing the potential for a dose-response association. We performed a systematic search of PubMed, Web of Science, CINAHL and Cochrane Central Register of Controlled Trials through June 2020, identifying ten observational studies (two prospective studies and eight case-control studies) for meta-analysis. We estimated summary OR and 95 % CI for the highest v. lowest olive oil intake category across studies using random effect models and assessed the dose-response relationship between olive oil and breast cancer risk using restricted cubic splines. The summary OR comparing women with the highest intake to those with the lowest category of olive oil intake was 0·48 (95 % CI 0·09, 2·70) in prospective studies and 0·76 (95 % CI 0·54, 1·06) in case-control studies, with evidence of substantial study heterogeneity (prospective I2 = 89 %, case-control I2 = 82 %). There was no significant dose-response relationship for olive oil and breast cancer risk; the OR for a 14 g/d increment was 0·93 (95 % CI 0·83, 1·04). There may be a potential inverse association between olive oil intake and breast cancer; however, since the estimates are non-significant and the certainty level is very low, additional prospective studies with better assessment of olive oil intake are needed.

Experimental Study of Heavy Oil Recovery Mechanisms during Cyclic Solvent Injection Processes

Summary The cyclic solvent injection (CSI) process has recently shown to be a promising method for enhanced heavy oil recovery in Canada. Laboratory testing is often run before development of field pilots to assess the effect of parameters, such as solvent choice and process conditions, on the CSI response. However, differences between laboratory results vs. field applications have been observed. CSI laboratory studies work for only two to three cycles due to low incremental oil in subsequent cycles, whereas field pilots continue for years over multiple cycles. This experimental study is intended to capture the production mechanisms responsible for heavy oil production in CSI. Primary production and CSI tests were conducted using sandpack models saturated with live heavy oil of 9530 mPa·s viscosity. The experiments were conducted in horizontal and vertical mode injection at high- and low-pressure depletion rates using two solvent mixtures of CH4 and C3H8. The sandpacks were scanned after every cycle to analyze the evolution of gas and oil saturations using computed tomography (CT). Three cores were used to study the effect of several parameters: gravity forces, pressure depletion rate, solvent composition, and initial oil saturation on the performance of CSI processes. CSI cycles run after primary production in horizontal systems produced negligible incremental oil for both slow and fast drawdown rates due to the large void space and high free gas saturation inhibiting the pressure buildup to push the solvent-diluted oil. These CSI experiments were only initially successful in dead oil systems, in which the initial oil saturation was higher and appropriate pressure gradient was generated through fast depletion rates. During the vertical alignment, CSI cycles exhibited higher incremental oil recovery per cycle. Slow depletion cycles were more efficient in terms of pressure and incremental recovery per cycle; however, faster depletion cycles performed better as a function of time. These results are more in line with the repeated recoveries measured over multiple cycles in field CSI pilot studies. More volume of diluted oil was drained out of the core when the solvent mixture with higher propane (C3H8) content was injected. These results demonstrate the importance of gravity drainage in the CSI process and its significance on successful oil recovery rates. This study illustrates the limitations of previous horizontal laboratory tests and shows an improved test configuration for modeling and prediction of the improved response observed in CSI pilots.

Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes

Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency.First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow.The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties.Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.

Dynamics of Live Oil Droplets and Natural Gas Bubbles in Deep Water.

Explaining the dynamics of gas-saturated live petroleum in deep water remains a challenge. Recently, Pesch et al. [ Environ. Eng. Sci. 2018, 35 (4), 289-299] reported laboratory experiments on methane-saturated oil droplets under emulated deep-water conditions, providing an opportunity to elucidate the underlying dynamical processes. We explain these observations with the Texas A&M Oil spill/Outfall Calculator (TAMOC), which models the pressure-, temperature-, and composition-dependent interactions between oil-gas phase transfer; aqueous dissolution; and densities and volumes of liquid oil droplets, gas bubbles, and two-phase droplet-bubble pairs. TAMOC reveals that aqueous dissolution removed >95% of the methane from ∼3.5 mm live oil droplets within 14.5 min, prior to gas bubble formation, during the experiments of Pesch et al. Additional simulations indicate that aqueous dissolution, fluid density changes, and gas-oil phase transitions (ebullition, condensation) may all contribute to the fates of live oil and gas in deep water, depending on the release conditions. Illustrative model scenarios suggest that 5 mm diameter gas bubbles released at a <470 m water depth can transport methane, ethane, and propane to the water surface. Ethane and propane can reach the water surface from much deeper releases of 5 mm diameter live oil droplets, during which ebullition occurs at water depths of <70 m.

Experimental Study of Blending CO2 with Triethyl Citrate for Mitigating Gravity Override During Reservoir Flooding

Challenges during CO2 flooding of oil reservoirs are mobility control and gravity override caused, respectively, by lower viscosity and density of CO2 compared with reservoir fluids. Blocking agents such as foam, cross-linked polymers and gels have been tested. However, such techniques are more effective in preventing fingering and blocking thief zones than reducing gravity override. Moreover, no foaming agent has been identified to withstand the high temperatures and salinities of some reservoirs. This experimental study investigates the use of triethyl citrate (TEC) as a densifying agent to blend with supercritical CO2 (scCO2) to minimize gravity override. High-permeability, Indiana limestone core samples saturated with either dead or live light crude oils at irreducible water saturations were flooded vertically upward at 24.132 MPa and 100 °C with about one pore volume of either pure scCO2 or a scCO2–TEC blend of 0.15 mol fraction (0.525 mass fraction) TEC. At breakthrough, scCO2 flooding of dead oil recovered 14.82% of the initial oil in place, while the blend flood recovered 31.99%. At 1 PV, the scCO2 flood recovered 60.14%, while the blend flood recovered 72.67%. The live-oil-saturated core samples produced similar results but with generally lower oil recoveries. At 1 PV of fluid injected, all floods reduced the oil saturation to levels lower than the residual oil saturation achieved with water flooding. With TEC’s low solubility in both crude oil and water, blending scCO2 with TEC is, thus, a technically viable method to mitigate gravity override in CO2–EOR process.

Novel laboratory investigation of huff-n-puff gas injection for shale oils under realistic reservoir conditions

Enhanced oil recovery (EOR) from shale oil formations is recognized as the next frontier in the exploitation of unconventional resources. Current approaches for performing EOR experiments using fractured rocks can generate misleading results as the fractured cores cannot be saturated with live oils. In this work, a novel laboratory methodology is developed to quantify the efficiency of gas huff-n-puff in shale oil formations under realistic reservoir conditions, i.e. live oil and hydraulic fracturing reservoir conditions. This new approach involves first saturating the shale core with oil and then hydraulic fracturing the oil-saturated core by increasing pore pressure above the core confining pressure. To demonstrate the viability of this new methodology, shale cores from the Haynesville formation with a permeability of 0.0001 mD were tested.Two huff-n-puff experiments were performed by the injection of associated gas into cores saturated with either dead crude oil or live oil. 48% additional oil recovery was achieved from the shale core saturated with live oil whereas, the shale core saturated with dead oil yielded a 33% enhanced oil recovery, which is significantly lower than that of the live oil. Furthermore, the pressure decay profiles during the soaking periods indicate a comparatively higher gas penetration into the live oil system despite the higher gas solubility in the dead oil. The in-situ gas formation can have a strong influence on the efficiency of huff-n-puff. The notable differences in the results obtained on live compared to dead oil experiments demonstrate the need to perform more realistic laboratory experiments to better optimize shale oil EOR-based extractions in the field.

The “Sardine run” along the Coastal Waters off Kanhangad (Kasaragod), South West Coast of India

The Sardine run associated with a bloom of the diatom genus Fragilariopsis was observed along the inshore coastal waters off Kanhangad during the last phase of the summer monsoon 2019. There was an unusual shoreward dumping of live oil sardines along with the waves throughout the day. High salinity (33 psu) and nutrient concentrations (Nitrate 16.33 μmol L−1 and silicate 13.9 μmol L−1) favoured the proliferation of Fragilariopsis spp. (7 × 104 cells L−1), in the coastal waters making them a major diet component of the oil sardines.

Pressure-sensitive characteristics of high-pour-point live oil and quantitative analysis of composition change

Previous studies on high-pour-point (PPT) oil have focused on the effects of temperature. There has been no systematic investigation of the pressure-sensitivity of crude oil, the deposition composition change of solid phases, and the effects of asphaltene deposition on wax precipitation. In the development of a high-PPT oil field, experiments using dead oil instead of live oil will exaggerate the effect of wax precipitation. In this paper, the wax appearance temperature (WAT), PPT, and asphaltene deposition pressure were obtained by the laser transmittance method. Subsequently, a new set of experimental devices and methods were developed to analyze the solid-phase components in live oil under various conditions. Finally, the viscosity of crude oil at various shear rates was measured with a capillary viscometer, and the wax network structure was evaluated. The experimental results showed that the WAT and PPT decrease with decreased pressure, and their fast decreasing ranges were 12–18 MPa and 15–18 MPa, respectively. The oil pressure-sensitivity not only includes the influence of wax; the appearance of the platform stage and trough pattern phenomenon proves that there is also the influence of asphaltenes. The main component of the deposition is C27+, and the amount of wax precipitated can reach 2.72%. For crude oil with a pressure lower than 15.83 MPa, the amount of asphaltene deposition reaches 0.04% at temperatures above WAT. Asphaltene can inhibit the aggregation and growth of wax crystal molecules, leading to a decrease in WAT and an increase in the viscosity at temperatures above WAT; however, the inhibition may be advanced or delayed with decreased pressure. Asphaltene also enhanced the strength of the wax crystal network structure, leading to an increase in the viscosity of crude oil at the critical shear stress under low pressure. When wax precipitation is dominant, there is a positive correlation between asphaltene deposition and wax, and the growth rate of wax is higher than that of nucleation in the early stage. This study improves the understanding of the effect of pressure on the physical properties of high-PTT live oil, provides reliable parameters for numerical simulations and the adjustment of the injection scheme, and lays the foundation for future evaluation experiments on wax removal chemicals.

Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems and Their Interplay

Summary Acoustic velocity is one of the key thermodynamic properties that can supplement phase behavior or pressure/volume/temperature (PVT) measurements of pure substances and mixtures. Several important fluid properties are relatively difficult to obtain through traditional measurement techniques, correlations, or equation of state (EOS) models. Acoustic measurements offer a simpler method to obtain some of these properties. In this work, we used an experimental method based on ultrasonic pulse-echo measurements in a high-pressure/high-temperature (HP/HT) cell to estimate acoustic velocity in fluid mixtures. We used this technique to estimate related key PVT parameters (such as compressibility), thereby bridging gaps in essential data. In particular, the effect of dilution with methane (CH4) and carbon dioxide (CO2) at pressures from 15 to 62 MPa and temperatures from 313 to 344 K is studied for two reservoir fluid systems to capture the effect of the gas/oil ratio (GOR) and density variations on measured viscosity and acoustic velocity. Correlative analysis of the acoustic velocity and viscosity data were then performed to develop an empirical correlation that is a function of GOR. Such a correlation can be useful for improving the interpretation of the sonic velocity response and the calibration of viscosity changes when areal fluid properties vary with GOR, especially in disequilibrium systems. In addition, under isothermal conditions, the acoustic velocity of a live oil decreases monotonically with decreasing pressure until the saturation point where the trend is reversed. This observation can also be used as a technique to estimate the saturation pressure of a live oil or as a byproduct of the target experiments. It supplements the classical pressure/volume measurements to determine the bubblepoint pressure.

Evaluation of enhanced oil recovery potential using gas/water flooding in a tight oil reservoir

In this study, experimental research was implemented to optimize production performance using flooding processes. Firstly, the phase behaviors of live oil–gas (N2, natural gas, and CO2) systems were studied in a pressure-volume-temperature cell to measure the properties of the gas-saturated live oil (including gas-oil ratio, oil-swelling factor, density, and viscosity). Secondly, water flooding and gas flooding were carried out in long-core plugs to study the mechanisms and production performance of water/gas flooding. The experimental results of the phase behaviors indicate that, among the three gases, CO2 is the best choice to boost the properties of live oil, evidenced by high mole fraction in the saturated oil (58.65 mol.%), high oil-swelling factor (1.4482), and high viscosity reduction ratio (90.6%). N2 showed the lowest property performance in the gas injection process when the phase behavior experiment was carried out. The production performance of water/gas flooding applied in the long-core plugs showed the following: (1) With water injection, earlier breakthrough occurred, and water flooding showed an oil recovery factor as high as 25.50%. (2) Compared with water flooding, the three gas-flooding processes achieved higher oil recovery factors. (3) With the best performance shown in the pressure-volume-temperature test, CO2 flooding could enhance oil recovery factor significantly; an oil recovery factor as high as 56.15% was obtained in the optimized flooding experiment with an injection rate of 0.10 cm3/min. CO2 storage potential was also investigated with CO2 flooding applied in a tight oil reservoir under reservoir conditions. At the end of the laboratory-scale test, a CO2 storage ratio of 56.92% was observed.

The Study of Extractionmethod of Hard-to-Recover Hydrocarbonstocks Using Oilfield Core Material

The displacement of hard-to-recover oil by water has become the most widespread method of crude oil extraction. However, in its implementation, the oil recovery factor is insignificant. Recently for this purpose the technology of water alternation gas injectionhas become widespread. In this work, the laboratory tests were carried out in conditions of artificial oil stratumusing the samples of live oil, water and gas. For the study were usedcore material samples selectedfrom the well ofoil fields. Experiments were conducted using different models of samples and fluids under conditions of maintaining the layer pressure and back pressure with a flow rate of 0.1 ml / min.

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.

Modeling asphaltene precipitation in Algerian oilfields with the CPA EoS

One of the major flow assurance problems afflicting the oil industry is the asphaltene precipitation during the production, transportation and storage of oil. The precipitation of these heavy compounds is responsible for changes in crude oil properties, increases in oil viscosity, and formation of deposits that reduce oil production and disable equipment leading to significant operational costs. In Algeria, the deposition of asphaltene in reservoirs and pipelines is a severe problem. During production the depressurization of reservoir fluid and the variations of thermodynamic conditions create the need to frequently pig the lines and, in some cases, to inject solvents and dispersants to maintain the production. The understanding of the asphaltene behavior and the prediction of its deposition in flow conditions is crucial to implement appropriate strategies for the prevention or remediation, especially in the wellbore region. In this work we used the CPA EoS to describe the asphaltene phase envelope and predict the PT regions of stability for five Algerian live oils. The model provides a very good description of the experimental behavior of live oils without and with gas injection. The sensitivity to SARA analysis data and its effect on the asphaltene phase boundaries were also analyzed.

A Fast Measurement of Asphaltene Onset Pressure

SummaryA technique to quickly determine the asphaltene onset pressure (AOP) of a crude oil from low-volume, nonequilibrium measurements is presented. The pressure at which the optical signature indicative of asphaltene aggregation is first detected in recombined crude oils is found to decrease strongly with the rate of depressurization and can be well-described with a modified power law. This technique exploits this rate dependence and uses two separate decompressions at highly disparate depressurization rates to determine the AOP. Benchmarking with this technique was performed with recombined crude oils that were characterized with conventional pressure/volume/temperature analysis. Using this technique, measurements enabling the determination of the AOP of a live crude oil can be obtained in minutes with a nominal uncertainty of 500 psi. This is a significant reduction in time compared with the multihour process used for conventional equilibrium-based measurements. Onset-time data from these studies are consistent with conventional aggregation theories, but there is insufficient range to differentiate between reaction-limited aggregation (RLA) and diffusion-limited aggregation (DLA).

Impact of Asphaltenes on Contact-Angle Variations and Surface Topography and Composition

Summary The asphaltene precipitation affects the rock/fluid interaction in a live-oil reservoir, which has a significant effect on oil recovery and flow in the production network. In this work, we examine the changes in interfacial properties (such as contact angle between the live-oil, brine, and quartz system) as well as surface topography and compositions caused by asphaltene precipitations that are related to pressure-depletion processes. The experimental method is based on the pendant-drop-shape method using a high-resolution camera for quantitative image analysis and a high-resolution digital-pressure transducer in a high-pressure high-temperature fluid cell. The contact angle with quartz was measured in the presence of deionized water as the surrounding medium at isothermal condition. The experiments were conducted in a pressure-depletion fashion, where pressure is decreased in steps capturing the asphaltene onset pressure (AOP). At each pressure stage, sufficient time was given to stabilize the contact angle. The transient experimental contact-angle data for a system containing a live oil, brine, and quartz is presented. In particular, we Show that the time of stabilization and contact angle decreases at sequential pressure steps, except near the vicinity of AOP where they have a sharp jump signifying the effect of asphaltene precipitation Use the solubility-parameter approach for asphaltene modeling to predict asphaltene precipitation from live oil at pressures between the saturation point and AOP Relate the amount of precipitation with change in interfacial properties, such as interfacial tension (IFT) and contact angle Use image-analysis techniques such as scanning electron microscope (SEM) and X-ray photoelectron spectroscopy (XPS) to analyze the topography and composition of the quartz surface after asphaltene deposition to supplement our observation Despite that asphaltene effects on wettability alteration have been proposed, this is the first experimental evidence that pressure-depletion-driven asphaltene precipitation alters the contact angle at realistic reservoir conditions (high-pressure high-temperature live oils). These data can be used as a basis to establish the benchmark data, model calibration for managing and preventing remediation asphaltene problems, and to design the proper facility and operating conditions for efficient recovery and operational processes.