Phase Behavior Of Crude Oil Research Articles

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

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

Effect of Tributyl Citrate as a Cosolvent on the Phase Behavior of Crude Oil during CO2 Injection Process

The current research on CO2 cosolvent primarily focuses on reducing the minimum miscibility pressure and improving oil recovery. However, investigations into the impact of additive agents on the phase behavior of crude oil during the CO2 injection process are relatively limited. In this study, we introduced tributyl citrate as a cosolvent to the CO2 injection process. By comparing the phase parameters of crude oil and changes in component composition in the residual oil before and after the addition of tributyl citrate, we explored the influence patterns of this cosolvent during CO2 injection. The experiments show that the optimum concentration of tributyl citrate is 0.3%. After the addition of tributyl citrate, the bubble point pressure of crude oil is reduced from 14.28 MPa to 13.36 MPa, and the density is decreased from 1.00 g/cm3 to 0.95 g/cm3. These alterations of bubble point pressure and density indicate an enhanced solubility of CO2 and improved miscibility with the oil, coinciding with an increased volume expansion coefficient rising from 1.12 to 1.18 under 20 MPa and a decrease in viscosity from 0.73 mPa·s to 0.64 mPa·s. Tributyl citrate primarily affects the properties of crude oil by reducing interfacial tension and the content of heavy components in the dissolution system. The addition of tributyl citrate stabilizes the deposition trend of heavy components in crude oil and promotes the transformation of heavy components into light components, thereby enhancing the efficiency of CO2 extraction. This study provides valuable insights into a novel and simple method to further increase oil recovery in the CO2 injection process.

The Phase Behavior Study of Air-foam Flooding in Changqing Ultra-Low Permeability Reservoirs

For phase change characteristics of air foam flooding in Changqing ultra-low permeability reservoirs,  experiments were performed with the air and the gas-phase oxidation of P-X diagram under reservoir conditions using the PVT high pressure physical device and gas chromatograph. The phase behavior of crude oil and air bubbles after multiple contacts was determined by PVT simulation and the phase equilibrium model. The critical temperature and critical pressure of crude oil were determined to be 424.4? and 9.85MPa. Results show gas dissolved in crude oil after oxidation was strong in the air under the same pressure. Because the foam system and crude oil emulsification during contact have produced multiple contact oxidation, the effect was less than that in air and oil, resulting in a relatively small oxidation of C2-C6, while the oxidation of C7-C16 was relatively more. Furthermore, the trend of gas phase composition approaching C2-C6 was relatively slow, while oil phase composition was closer to C7+, due to the increase in the C7-C16 component. The study provides important insight for miscible flooding and non-miscible flooding applications, as well as for gas injection project design.

An Integrated Review on Asphaltene: Definition, Chemical Composition, Properties, and Methods for Determining Onset Precipitation

Summary Asphaltene is a solid oil component with a wide range of molecular compositions and structures, making it one of oil’s most complicated components. The deposition and precipitation of asphaltene in several places along the oil production line, such as the wellbore, reservoir, flow lines, tubing, and the separation unit at the surface, of the most prevalent flow assurance challenges. Changes in pressure, composition, and temperature cause asphaltene to precipitate out of the oil continuum. Variations in operation condition are caused by various recovery processes (gas injection, natural depletion, and chemical injection) in addition to the creation and blending of various oils during transportation. This paper presents a complete review of asphaltene precipitation (AP) and deposition (AD), which in turn helps in understanding the governing mechanisms and thermodynamic behaviors in this field. This study consists of several stages: analyzing the current state of asphaltene research (asphaltene characteristics, chemical nature, molecular structure, asphaltene crude oil phase behavior, solubility factors, and other factors); describing the phases of asphaltene (from its stability through its deposition in the reservoir pores, facilities, wellbore path in addition to the reasons for their occurrence); clarifying the rheology and asphaltene flow behavior in the reservoir; and finally examining the advantages and disadvantages of most widely used strategies for determining onset AP. In addition, some measured Iraqi asphaltene data are demonstrated and analyzed. This work will contribute to better knowledge of asphaltene and will serve as a reference for future studies on how to properly investigate and simulate asphaltene.

Mechanistic Understanding of Delayed Oil Breakthrough with Nanopore Confinement in Near-Critical Point Shale Oil Reservoirs

Recently, significant breakthroughs have been made in exploring northeast China’s shale part of the Q formation. On-site observation reveals that the appearance of oil at the wellhead is only seen a long time after fracturing in many wells. Strong coupling between phase behavior and relative permeability curves in the reservoir with the near-critical point initial condition restricts the efficient development of this kind of shale oil. A series of compositional models are constructed to address the issues to reveal the cause of the late oil breakthrough. Nanopore confinement is checked by including this phenomenon in the numerical model. Before the simulations, the work gives detailed descriptions of the geology and petrophysics background of the target formation. Simulation results show that the delayed oil breakthrough is highly related to the coexistence of three phases at the beginning of production, which is not seen in common reservoirs. The extended period of purely water production complicates subsurface flow behavior and hinders the increase of medium- and long-term oil production. Early-time production behavior in such reservoirs is associated with the gas–liquid relative permeability curves and initial water saturation. Oil–water relative permeability curves affect the water-cut behavior depending on wetting properties. The potential oil-wet property slows down oil breakthroughs. Conceivably, purely gas and water phases exist due to the nanopore confinement of crude oil phase behavior; thus, the late oil production is barely related to the gas–liquid relative permeability curves.

Hpm-Swir: Additional Configuration to High Opacity Crude Oil Phase Behavior Determination at High Pressure and High Temperature

Hpm-Swir: Additional Configuration to High Opacity Crude Oil Phase Behavior Determination at High Pressure and High Temperature

Modified PC-SAFT characterization technique for modeling asphaltenic crude oil phase behavior

The perturbed-chain version of Statistical Association Fluid Theory (PC-SAFT) emerged as a powerful tool to study the phase behavior of complex fluids such as polymers and asphaltene. In spite of this, it has not gained widespread acceptance in the industry because of its sophisticated oil characterization procedure. In fact, the predictive performance of the current characterization methods is limited and not all-inclusive as they use a large number of fitting parameters and/or a non-integrated procedure. In this study, a convenient and easy-to-use procedure for crude oil characterization is proposed, assuming asphaltene as a combination of poly-nuclear aromatics, benzene derivatives, and saturates.To achieve the best match between measured and model predictions, a simple and robust Trust-Region based optimization method is used. A set of weighting factors is also used based on uncertainties in experimental data. Additionally, it is showed that the poor agreement between the measured amounts of precipitated asphaltene (from filtration test) and thermodynamic model predictions —tuned toward experimental asphaltene onset pressure data— is because of the inherent difference between the accuracy of the experimental methods.The performance of the proposed method is evaluated against reliable literature data of three frequently used crude oils which have been previously characterized over wide range of temperature, pressure, and compositions, and a reservoir fluid sample taken from a southwestern Iranian reservoir. The results are encouraging if compared to the available characterization procedures in the literature.

Phase behavior and miscible mechanism in the displacement of crude oil with associated sour gas

The re-injection of associated sour gas, with high H2S and CO2 content, into the reservoir is proposed to be an effective development method due to its low investment cost and high oil recovery. The aim of this work is to present the phase behavior and miscible mechanism of crude oil displaced by associated sour gas. Based on the equation of state and the phase equilibrium theory, the phase behavior of crude oil mixed with various gases (associated sour gas, H2S, CO2 and CH4) have been analyzed. Then, the miscibility of associated sour gas was determined by calculating its Minimum Miscible Pressure (MMP) and the effect of sour component fraction on miscibility was evaluated. Moreover, a series of numerical simulations modeling 1D slim-tube were conducted using a compositional simulator to study the miscible mechanism in the displacement of crude oil with associated sour gas. The results show that the injection of H2S can reduce the bubble point pressure of crude oil and therefore is beneficial to prevent the crude oil degassing; nevertheless, the injection of CO2 has little effect on it. The miscible ability of associated sour gas decreases as its sour component fraction decreases. It is observed that the crude oil displaced by associated sour gas and sweet gas both show a combined condensing/vaporizing mechanism, with miscible zone in the middle of transition zone. However, the vaporizing-gas drive mechanism is slightly stronger than the condensing-gas drive mechanism during the displacement by associated sour gas while is significantly stronger during the displacement by sweet gas.

Experimental investigation of shale oil recovery from Qianjiang core samples by the CO2 huff-n-puff EOR method.

CO2 Huff-n-Puff (HnP) is an effective technique for enhancing oil recovery (EOR) that can be applied to shale oil reservoirs faced with poor natural productivity and low water injectivity. The main objective of this study is to investigate the interactions of CO2 and formation crude oil, and evaluate the CO2 HnP performance in shale oil reservoirs in the Qianjiang depression in China. In this study, the variation rules of oil phase behavior, viscosity, saturation pressure, and swelling factor at different CO2 contents of 0 to 65% were studied. A series of HnP experiments were conducted. The factors affecting the oil recovery were discussed, and Nuclear Magnetic Resonance (NMR) tests were conducted on core samples at different stages of the HnP process. The results show that the injected CO2 can make an positive change in the crude oil phase behavior. The oil–gas two-phase region enlarges and the saturation pressure increases as more CO2 is dissolved in the formation oil, which is beneficial to oil production. The dissolution of CO2 in the oil phase increased the oil swelling degree by 1.492 times, and the viscosity decreased from 1.944 to 0.453 mPa s. The HnP experimental results demonstrate that the soaking time should be determined based on the injection pressure. Miscible conditions is a viable option for CO2 HnP as 10% more oil can be produced using miscible HnP and save more than half of the soaking time. The results illustrate that fracture is the most important factor affecting oil recovery, and the performance of HnP EOR on core samples with fractures is almost 25% better than those without fractures. However, the core matrix permeability has an almost negligible effect on the performance of CO2 HnP. The NMR tests show that the oil recovered in the first cycle was dominated by macropores and mesopores, followed by small pores. In the latter HnP cycles, the oil in small pores and micropores becomes the main oil-producing area. This study may provide a better understanding of the CO2 HnP enhanced recovery strategy for shale reservoirs.

Use of real crude oil fractions to describe the high pressure phase behavior of crude oil in carbon dioxide

The knowledge about crude oil phase behavior at high-pressures is a challenge for scientists due to inherent complexity to this systems. Some works employ model systems attempting to predict crude oil behavior, but the results are normally poor. In this sense, the use of real crude oil fractions can be an alternative to improve the accuracy of the models used in these simulations. In this work, a light oil sample has been fractionated to generate four representative fractions. An approach to estimate the critical properties of these distilled fractions using only density and vapor pressure experimental data is presented. In sequence, phase behavior of the pseudo binary (carbon dioxide (CO2)+real crude oil fractions), multicomponent (mixture of fractions+CO2) and original crude oil+CO2 systems were determined using static synthetic method and static synthetic+NIR, with CO2 molar fraction range of 0.367-0.986, temperature range of 20⿿80°C and pressure up to 300bar. Binary interaction parameters (BIP) were estimated for each pair (CO2+distilled fraction) and employed to describe the phase behavior of a CO2+crude oil systems with Peng-Robinson equation of state (PR-EOS) and quadratic mixing rule. The results suggest that the use of real fractions can be a safer strategy for predicting the phase behavior of petroleum in carbon dioxide. Besides, NIR spectroscopy showed to be a good alternative to study phase behavior of dark/opaque systems.

Experimental investigation of DME–water–crude oil phase behavior and PVT modeling for the application of DME-enhanced waterflooding

Due to first contact miscibility with hydrocarbons and partial miscibility with water/brine, DME has shown a significant potential for enhanced waterflooding technology that has been developed recently in Shell. To provide a solid foundation for this EOR application, understanding the phase behavior of DME–brine–oil systems is crucial – which is practically non-existent for the conditions of interest in the open literature. We perform experimental study to measure partitioning of DME between hydrocarbon and aqueous phases. We also develop a PVT model using cubic plus association (CPA) to characterize the mixture of DME, water/brine and hydrocarbons based on experimental data. Finally, we investigate the dependency of the partitioning coefficient on feed per phase and show that it decreases with increase in DME mole fraction in hydrocarbon phase while increases with increase in salinity.

Alkanes Induced Asphaltene Precipitation Studies at High Pressure and Temperature in the Presence of Argon

The continuous increase of petroleum production under adverse subsea conditions and the preeminent need for adequate operational conditions and efficient use of additives to warrant flow assurance makes it interesting to set up experimental procedures to carry out n-alkane precipitation studies under high-pressure (p) and high-temperature (T) conditions. In this contribution, some preliminary experimental studies developed to characterize asphaltene precipitation in model systems consisting of asphaltene solutions in toluene or mixtures of hydrocarbons by the addition of propane, n-heptane, or other alkanes at various pressures and temperatures, using a commercial compact equipment, are reported. In general terms, it was established that these tests follow the same pattern described at ambient p and T conditions and the one single study reported in the literature for a stock tank oil sample at 3000 psi and room T. Four crude oils of different characteristics were tested, using diluted or undiluted samples, and it was possible to detect the asphaltene precipitation onset. However, these results cannot be used to infer the stability of the crude oils because results correlating onset and stability at high p and T are not yet available. The effect of pressure at high pressures was not entirely resolved because argon, used as an assumed inert gas to pressurize the system, dissolves in the hydrocarbons and displaces the precipitation onset toward lower values. The need to develop compact equipment to assess the effect of solvents, inhibitors, and other additives on the phase behavior of crude oil at high pressure and temperature and in the presence of CO2 and other gases, representing a valuable contribution to the petroleum industry in the area of flow assurance, still persists.

Chemical Visualization of Asphaltenes Aggregation Processes Studied in Situ with ATR-FTIR Spectroscopic Imaging and NMR Imaging

Crude oil phase behavior and asphaltene precipitation have been studied by two complementary chemical imaging methods for the first time. ATR-FTIR spectroscopic imaging approach has revealed the chemical composition of agglomerated and precipitated asphaltenes upon dilution with a flocculant. Asphaltenes, containing oxygen and nitrogen heteroatomic functional groups, have been detected to be least stable. Aromatic abundant asphaltenes have been observed to have relatively high solubility in crude oil/heptane blends. NMR imaging approach, capable of imaging in the bulk of crude oil samples, has demonstrated that n-heptane causes aggregation which can lead to the stable suspension or to the sedimentation followed by the formation of deposits, depending on flocculant concentration. These processes have been monitored for small and large amounts of heptane added to crude oil. The data obtained by ATR-FTIR spectroscopic imaging and NMR imaging have been correlated to propose a possible link between the chemica...

Effects of CO2 Injection on Phase Behavior of Crude Oil

CO2 flooding is a win-win technology, sequestrating greenhouse CO2 while producing a significant amount of crude oil to help defray the cost of CO2 sequestrating and enhancing oil recovery. However, due to the difference of sedimentary environment and poor properties of formations, physical properties of the crude oil and the effect of CO2 flooding are not always satisfactory in most oilfields of China. Therefore, in this article, to improve the understanding of the oil recovery mechanisms and feasibility of CO2 flooding in China, based on the oil and gas of Mao-3 oilfields, phase behavior of the CO2 and crude oil system was investigated. Parameters like saturated pressure, volume factor, gas oil ratio, and viscosity were measured and their relationships analyzed. Results show that crude oil of Mao-3 reservoir and CO2 has good mutual dissolution under reservoir conditions, and CO2 could expand the oil and reduce the oil viscosity greatly. As a result, formation energy could be enhanced and flow characteristics of the oil could be improved by CO2 flooding.

Engineering Applications of Phase Behavior of Crude Oil and Condensate Systems (includes associated papers 16046, 16177, 16390, 16440, 19214 and 19893 )

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary Fluid samples must be taken early in the life of a reservoir toobtain samples truly representative of the reservoir fluid. They should betaken only after a carefully planned well conditioning and testing program. When the PVT data obtained from these samples are used, care should be taken toadjust FVF's and gas/oil ratios (GOR's) for surface separator conditions. Introduction The proper development, engineering, and production of an oil or gasreservoir requires a considerable amount of planning. At the same time thatplans are formulated to develop the field, plans should also be made for adata-gathering program to facilitate reservoir engineering months and evenyears into the future. This data-gathering plan should include a sufficientnumber and variety of electric logs and cores on key wells to describe thereservoir adequately. Electric logs and core analyses evaluate the reservoirrock. If reservoir engineering calculations are to be made to optimizeproduction from a reservoir, including EOR, then the properties of thereservoir fluids must also be known. The properties of the reservoir water fallwithin narrow ranges and are seldom studied at reservoir pressures andtemperatures. The properties of the reservoir water determined are normallyconfined to chemical analysis and possibly compatibility tests in cases ofinjection projects. This paper is concerned primarily with the study of thehydrocarbon fluids contained in a reservoir. Coring and logging programs shouldcontinue throughout the development of a reservoir. The data obtained from thelast well drilled are as valuable as the data obtained from the first well. This is usually not the case for reservoir fluids. Samples representative ofthe original reservoir can be obtained only when the reservoir pressure isequal to or higher than the original bubblepoint or dewpoint. Methods areavailable for extrapolating fluid data obtained after some pressure decline. Remember, however, that extrapolation is an educated man's word for guessing. Plans for obtaining reservoir fluid samples and analyses should be made earlyin the life of a reservoir. Reservoir fluid samples should be taken beforesignificant reservoir pressure decline has been experienced. Oil Reservoirs Oil reservoirs can be divided into two categories: ordinary oil reservoirsand near-critical reservoirs. The ordinary oil reservoirs are sometimes calledblack-oil reservoirs. This misnomer does not reflect the color of the reservoirfluids. It is meant only to distinguish them from near-critical oil reservoirfluids. The near-critical fluids will be discussed in subsequent paragraphs. Ordinary oils are characterized by GOR's up to approximately 2,000 ft3/bbl [360m3/m3], oil gravities up to 45 degrees API [0.8 g/cm3], and FVF's of less than2 bbl/bbl [2 m3/m3]. Remember that there is no sharp dividing line between anordinary and a near-critical oil. Such factors as composition and reservoirtemperature greatly influence the behavior of the reservoir fluid. It is oftenimpossible to determine whether a fluid should be studied as a near-criticaloil or as an ordinary oil until it is actually in the laboratory beingobserved. JPT P. 715^