Asphaltene Precipitation Envelope Research Articles

Prediction of Asphaltene Precipitation Envelope (APE) Using Empirical Equations and Equation of State Model

Prediction of Asphaltene Precipitation Envelope (APE) Using Empirical Equations and Equation of State Model

Laboratory Investigation of Permeability Impairment Caused by Asphaltene Precipitation during Screening for Gas-Injection Enhanced Oil Recovery and Pressure Change in a Major Gulf of Mexico Field

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.

A comparative study of CPA and PC-SAFT equations of state to calculate the asphaltene onset pressure and phase envelope

The Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) equation of state (EoS) and the Cubic-Plus-Association (CPA) EoS have been widely applied to describe the asphaltene precipitation onset in crude oils because the association term of these models can appropriately account for the polar-polar interactions between asphaltene and resin molecules. In this study we have compared the PC-SAFT and CPA EoS capabilities in the calculation of the Asphaltene Precipitation Envelope (APE) of eight oils from the literature and discuss the physical meaning of the cross-association energy parameter between asphaltene and resin. For all oils the PC-SAFT EoS predicts an increase in the stability of the oil at higher temperatures with the consequent closure of the APE while the CPA model predicts a decrease in the stability at higher temperatures. For both models the fitted values of the cross-association energy parameter between asphaltene and resin show a dependency on temperature, but for PC-SAFT model this parameter has a clearer physical meaning. Results indicate that the PC-SAFT EoS is more accurate for APE calculations outside the experimental temperature range.

Effect of Brine on Asphaltene Precipitation at High Pressures in Oil Reservoirs

In this study, the effect of NaCl, KCl, CaCl2, MgCl2, MgSO4, and CaCl2 salts in brine in the range of low (1000−5000 ppm) and intermediate (5000−40 000 ppm) salinity water on the amount and offset pressure of asphaltene precipitation was investigated. The measurements were performed at reservoir temperature (350.15 K) and high pressures (0−100 bar). The IFT (Interfacial Tension) values increased with pressure and a sudden increase was observed at a specific pressure namely, an offset pressure of asphaltene precipitation in APE (Asphaltene Precipitation Envelope). For all brines, the amount of IFT with increasing concentration was in descending order and after a minimum value it changed to uptrend. Likewise, similar results were obtained for the precipitated asphaltene amount. All the brines intensified the asphaltene precipitation. Monovalent cations like Na+ and K+ showed higher values of IFT and hence more asphaltene precipitation, however, MgCl2 showed the least IFT, offset pressure and the amount of asphaltene precipitation.

Effects of hydrophobic CaO and SiO2 nanoparticles on Asphaltene Precipitation Envelope (APE): an experimental and modeling approach

An experimental and modeling approach was developed in this research to investigate the effects of CO2, new synthesized CaO and commercial SiO2 nanoparticle concentrations on the Asphaltene Precipitation Envelope (APE). First, the effects of different temperatures and CO2 concentrations on asphaltene precipitation trends were observed. Second, the impact of CaO and SiO2 nanoparticle concentrations on asphaltene precipitation were observed in the presence of CO2 at different temperatures. Third, Advanced Redlich-Kwong-Soave (RKSA) equation of state (EOS) was considered to modify Multiflash (Infochem Co.) software from the aspect of entering physical characteristics of CaO and SiO2 nanoparticles as pseudo components. Fourth, the developed model was used for predicting the effects of CO2, CaO and SiO2 concentrations on APE in ranges that no experimental data existed. At constant CO2 concentration and temperature during natural depletion, asphaltene precipitation increased above saturation pressure, while below saturation pressure, asphaltene precipitation decreased (solution gas evolved from crude oil and made it richer). As temperature increased at constant CO2 concentration, asphaltene precipitation decreased, while it was observed that the saturation pressures increased. Although two different trends were observed in upper asphaltene onsets at different temperatures and CO2 concentrations, in wide ranges of data, as temperature increased, asphaltene upper onset pressure increased. CaO and SiO2 nanoparticles decreased asphaltene precipitations in the presence of CO2, but CaO had better applications for reducing asphaltene precipitation. The proposed Software/RKSA EOS model was in good agreement with the obtained experimental data, and it was applicable for predicting the effects of CO2, CaO and SiO2 nanoparticles concentration on APE.

Simulation of asphaltene precipitation during gas injection using PC-SAFT EOS

Oilfield problems owing to asphaltene precipitation are well known. Asphaltenes can block pore throats or change the formation wettability and thereby reduce the hydrocarbon mobility. Simulation of asphaltene precipitation during gas injection requires a comprehensive thermodynamic model, which accounts for the complex phase behavior of asphaltenes. In this paper, PC-SAFT EOS is implemented for the first time in a compositional reservoir simulator to model asphaltene precipitation. The additional computational time of PC-SAFT compared to the cubic equations-of-state such as Pen-Robinson (PR EOS) is decreased by improving its root finding algorithm. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate the dynamics of precipitated asphaltenes. Different gas injection scenarios are modeled to show the effect of gas injection on apshaltene precipitation and deposition.Simulation results show that the profile of the damaged area by asphaltene deposition is governed by the shape of the asphaltene precipitation envelope for the reservoir fluid. The damage caused by asphaltene deposition, through plugging and wettability alteration, was revealed as a decline in productivity index curves. Results indicate that a reservoir fluid can have precipitation risk during gas injection even if it does not exhibit precipitation in the primary recovery life of a field. The computational time of the simulations using PC-SAFT EOS were compared to those using PR EOS for different number of components. Results of these comparisons show the feasibility of using PC-SAFT in compositional simulations.

Emerging Numerical-Modeling Technique To Evaluate Asphaltene-Inhibitor Efficiency During Entire Field Life

Summary This work sought to establish a robust asphaltene flow-assurance engineering with asphaltene inhibitor to mitigate the risk of asphaltene precipitation in tubing. For this purpose, the best candidate was selected through the asphaltene dispersant test (ADT). Furthermore, its inhibiting efficiency was evaluated by generating a numerical model. The purpose of this evaluation was to predict how its efficiency varied during entire field life in which production conditions changed in early and late life. Through the two-stage ADT, the best inhibitor IB-23 was selected from a total of nineteen samples. The IB-23 revealed a high inhibiting efficiency of more than 80% at 200 ppm concentration, and maintained its efficiency more than 70% even at 10 ppm. Currently, any commercial software is not available for the modeling of asphaltene inhibitor caused by confidentiality for inhibitor physical data. This study achieved modeling of inhibiting efficiency by treating an inhibitor as a pseudoresin and/or pseudocomponent. It could be defined with limited physical data that were available in a publicly accessible material-safety data sheet (MSDS). The numerical model was generated with a cubic-plus-association (CPA) equation of state (EOS) together with the conventional fluid characterization to characterize the asphaltene crudes. This paper demonstrates that the numerical model expressed the inhibiting efficiency as a size-reduction of asphaltene-precipitation envelope (APE) and a decrease in the amount of asphaltene precipitated. The model validity was checked by comparing with experimentally measured weight data of asphaltene deposits during the ADT. Assuming natural depletion, the APEs were compared with a variation of vertical lifting curves (VLCs) in tubing. Two VLCs were assumed to represent early and late field conditions (i.e., high wellhead/reservoir pressures and depleted ones). The no-inhibitor case revealed that precipitating risk existed over most of the tubing section. In contrast, the inhibitor-dosed case could significantly reduce the risks in the early stage in particular. Even in the late stage, the risks could be minimized because the interception of VLC on the APE became shorter than that of the no-inhibitor case. Asphaltene inhibitor is a typical countermeasure; however, most of the applications offer only temporary relief. Through an entire field life, the production conditions vary such as pressure decline, gas/oil ratio (GOR) increase, and others. Accordingly, the efficiency of the inhibitor, initially selected as the best, fades away. Then, another screening would be required to select an alternative one that can adapt effectiveness to the new operating condition. This paper contributes to estimating its inhibiting efficiency during a whole field life.

Effect of pressure of the onset of asphaltene precipitation during gas flooding

ABSTRACTIn order to prevent and eliminate the asphaltene precipitation during gas flooding, the rules of the changes of the pressure under different conditions are systematically studied by the laser solid detection system, the light transmission method, and the P–T phase diagram when the asphaltene precipitation occurs. When the pressure is reducing to a certain value, the penetrating light intensity of the crude oil is markedly decreased, which shows that the pressure at this point is the pressure of the onset of asphaltene precipitation (AOPP). The AOPP value decreases with an increase in the temperature. During gas flooding, the AOPP value increases with an increase in the content of gas in the crude oil, and these two nearly do have a linear relationship. According to the P–T phase behaviors of the gas–crude oil system, with an increase in the content of gas in the crude oil, the asphaltene precipitation envelope curve (APE) is gradually moved up, which shows that the possibility of asphaltene precipitation is much higher. During oil production, for the oil reservoirs with rich asphaltene, the production pressure drop should be kept a small value to ensure that the flowing bottom-hole pressure is higher than AOPP and it is necessary to help complement producing energy timely by using water injection, gas injection, etc. Besides, according to the intersection of T–P curve and APE curve in the P–T phase diagram, the location where the asphaltene precipitation occurs in the wellbore can be roughly predicted. The experimental results can provide the theoretical foundation for taking measures to prevent and eliminate the asphaltene precipitation.

Managing Experimental-Data Shortfalls for Fair Screening at Concept Selection: Case Study To Estimate How Acid-Gas Injection Affects Asphaltene-Precipitation Behavior

Summary In a carbonate field under high pressure and high temperature (HP/HT), a gas-injection scheme has been assessed to improve oil recovery through pressure maintenance and miscible displacement. The potential study assumed sequential application of several gas-injection concepts, including raw-gas injection (RGI) and acid-gas injection (AGI). Flow-simulation studies of these concepts revealed a variety of compositional changes to the in-situ fluid, depending on the injection scheme and composition of the injected gases. Fluid compositional change is a common trigger of asphaltene instability; therefore, to ensure a robust gas-injection development, it is important to evaluate the risk of asphaltene precipitation. Because of high hydrogen sulfide (H2S) concentrations of AGI fluid under HP/HT in-situ reservoir conditions, it is difficult to take an experimental approach for evaluating gas-mixed asphaltene-flow assurance at a normal laboratory. Hence, at the concept-selection stage, this paper focuses on an alternative approach for numerical-modeling analysis of the AGI scenario, and presents the way in which AGI impacts asphaltene-precipitation behavior. On the basis of the asphaltene model established by applying a cubic-plus-association (CPA) equation of state (EOS), which was calibrated with the experimentally measured asphaltene-onset pressure (AOP), a new binary-interaction-parameter (BIP) correlation between H2S and hydrocarbons was incorporated to evaluate variation of the asphaltene-precipitation envelope (APE) with periodic compositional change observed from the AGI-flow simulation. In the AGI scenario, injection gas was assumed to be 90 mol% H2S and 10 mol% carbon dioxide (CO2). The original reservoir fluid contains 15 mol% H2S concentration. During the 3D reservoir-simulation study for the AGI scenario, H2S concentration in produced fluid was observed to increase up to 76 mol% at a well located near acid-gas injectors. In the APE sensitivity analysis that was conducted independently for each composition of H2S and CO2, the asphaltene model revealed that the base APE decreased as the H2S concentration increased and expanded as the CO2 concentration increased. As a result, for the mixed compositions, the opposing effects on the APE offset each other, and the acid-gas addition produced a subsequent decrease of the APE. In summary, this work supported a relative merit of AGI from a thermodynamic asphaltene-flow-assurance point of view, while verification is needed with experimental data in the next defined/detailed engineering stages. From stage-gate process-engineering points of view, this case study is also worthy to appropriately estimate potential concepts that have complexity of technical evaluation. Such complexity might be encountered when assuming an emerging condition or when introducing emerging technologies. In such cases, potential concepts are often difficult to evaluate fairly with existing technologies, but can possibly be evaluated with newly introduced or developing evaluation measures. However, these new and developing measures require cost that can be justified at the matured stage of development, but that cannot be justified at the concept-screening stage. In the future, the exploration and production (E&P) industry will be required to access more emerging fields of lesser easy oil; thus, this case study will be an example engaging a similar situation.

Experimental Investigation and Application of the Asphaltene Precipitation Envelope

In the production process, the asphaltene precipitation (AP) and deposition can not only inflict damage on reservoir stratum but also lead to the shut-in of the well and incur the extra cost of remediation. In this study, the phase behavior of asphaltenes in live oil under high-temperature and high-pressure conditions was determined using a modified solid (asphaltene) deposition laser detection apparatus. The test accuracy was greatly improved as a result of the increase of the laser power. The phase behavior of asphaltenes in live oil, which was characterized by the heavy components and dark color, was evaluated. The oil sample was from the Fahliyan oilfield in Iran, which is suffering big AP problems. In addition, the values of the bubble point pressure (BPP) obtained by this apparatus have proven to be well-matched with that measured by the constant composition experiment (CCE) test. Moreover, the equation of state (EOS) of the asphaltene and crude oil obtained by the fitting curve can be used to furth...

Prediction of the Gas Injection Effect on the Asphaltene Phase Envelope

Asphaltene instability may occur when pressure, temperature and compositional variations affect the reservoir oil. Permeability reduction, wettability alteration, and plugging of wells and flow lines are the consequences of this phenomenon. Therefore, it is crucial to investigate the asphaltene behavior in different thermodynamic conditions by knowing the Asphaltene Precipitation Envelope (APE) in a preventive way rather than the costly clean-up procedures. The selected reservoir oil has faced a remarkable decline in production due to several years of extraction, and Enhanced Oil Recovery (EOR) has been considered as a solution. Therefore, in this paper, a comprehensive study was carried out to predict the effects of different injected gases on asphaltene onset and to prevent future asphaltene precipitation based on the laboratory data. The Advanced Redlich-Kwong-Soave (RKSA) equation of state was considered to develop APE using Multiflash ( Infochem Co .). For the selected reservoir oil, with temperature reduction at low temperatures, asphaltene precipitation weakened and made the onset pressure decrease, so this behavior is different from the results obtained in other published reports. On the basis of this model, several sensitivity analyses were performed with different gases ( i.e. , methane, CO 2 , N 2 and associated gases) to compare the risk of each gas for future EOR strategies. APE tend to expand as the amount of injected gases increases, except for CO 2 gas injection, that showed another unconventional behavior for this crude oil. It was observed that for CO 2 gas injection below a certain temperature, asphaltene stability increased, which can be considered as a good inhibitor of asphaltene precipitation.

Determination of the Asphaltene Precipitation Envelope and Bubble Point Pressure for a Mexican Crude Oil by Scanning Transitiometry

In this work, the phase transitions (liquid–solid, liquid–vapor, and solid–liquid) for a Mexican crude oil were measured with the transitiometric technique over wide temperature and pressure ranges to determine its asphaltene envelope. A titration of this crude oil with n-heptane based on ASTM D3279 and ASTM D4124 standard methods was carried out to make sure that the phase transition corresponds to the asphaltene precipitation. As a result of the experimental work performed here, it is shown that scanning transitiometry is a suitable experimental technique that can be used to determine the asphaltene precipitation onset and the bubble point pressures for a variety of crude oils, where the density of the crude oil is not a limiting factor. The thermodynamic modeling of the asphaltene precipitation envelope was successfully performed using the statistical associating fluid theory for potentials of variable range (SAFT-VR) equation of state (EoS) in the framework of the McMillan–Mayer theory, as reported by...

Asphaltene precipitation in live crude oil during natural depletion: Experimental investigation and modeling

The complicated nature of asphaltene molecules besides the unknown mechanism of phase separation of asphaltene-containing systems as well as lack of a suitable characterization parameter has questioned the generality of the available thermodynamic models.The scaling equation developed by Rassamdana et al. [10,13] and its generalized form presented by Hu et al. [20] proved existence of a general relationship to model the asphaltene precipitation envelope and the onset. However, it works only for dead oil systems; here it has been tried to extend this technique for live oil fluids at reservoir condition. In this study, three types of experiments were conducted on five live reservoir fluid samples. The samples were collected from a giant Iranian oil field to measure the amount of precipitated asphaltene for a wide range of temperature and pressure.The results of this study developed a new live oil scaling equation and successfully applied to predict a new real data-set. The predictions of the model were compared with the two widely used thermodynamic methods of single component solid and modified Flory–Huggins (FH) models. The results show that the phase stability and the regions where asphaltene precipitates from the live crude oil were predicted using this new scaling equation with an acceptable accuracy.

Dynamic Asphaltene Behavior for Gas-Injection Risk Analysis

Summary Asphaltene study is now becoming a regular menu as a part of gas-injection studies (Kokal et al. 2003, 2004; Yin et al. 2000; Srivastava et al. 1999; Yin and Yen 2000; Parra-Ramirez et al. 2001; Sarma 2003; Jamaluddin et al. 2000; Negahban et al. 2005; Okwen 2006; Moghadasi et al. 2006). The asphaltene onset pressure (AOP) is one of the most important factors in understanding asphaltene precipitating behavior. The solid detection system (SDS) based on light-scattering technique has been quite popular and widely used in all over the world (Kokal et al. 2003, 2004; Jamaluddin et al. 2000; Negahban et al. 2005; Gholoum et al. 2003; Garcia et al. 2001; Oskui et al. 2006; Gonzalez et al. 2007) to measure AOP. The simple experiments to measure AOP are usually conducted using a mixture of reservoir fluid and injection gas, and various gas-mixing volumes are assumed to be investigated. These various experimental specifications of gas-mixing volume are useful in understanding asphaltene risks during gas-injection projects. However, this type of investigation can show only a static asphaltene behavior, and sometimes might overlook true asphaltene risks. In the gas-injection pilot (GIP) project in an offshore carbonate oil field in the Arabian Gulf, the static asphaltene behavior was studied by the SDS using near-infrared (NIR) light-scattering technique. For this study, a single-phase bottomhole sample was collected from the same producing zone, but the sampling location was 90 ft shallower than the GIP area. Various combinations of mixtures were examined to measure AOP (i.e., reservoir fluid mixed with 0, 25, 37.5, 43.5, and 50 mol% injection gas). Furthermore, the numerical models were generated and calibrated with the experimental findings. To evaluate the asphaltene risks at the GIP area, the models were adjusted to the target oil composition by considering existing oil compositional gradient in the field. However, the modeling analyses showed that the operating conditions of producing wells are outside the estimated asphaltene-precipitation envelope (APE). This result was inconsistent with the field fact in which actual asphaltene deposits were observed and collected from the bottomhole of some wells in the GIP area. Thus we were obliged to recognize that our current experimental results of static asphaltene behavior overlooked the actual asphaltene risks. What is insufficient for realistic modeling? Our hypothesis is the dynamic asphaltene behavior. During a gas-injection process, the injected-gas composition is changed because of a vaporizing-gas-drive (VGD) mechanism, in which gas was enriched with the intermediate-molecular-weight hydrocarbons from reservoir oil. Our latest experiments investigated a static asphaltene behavior only; that is, it did not include this process. Therefore, the sensitivity analyses were motivated to realistically evaluate the actual APE, counting the VGD effects with the calibrated model. Various enriched-gas compositions were investigated in terms of how these enriched gases would affect APE. Consequently, it was found that the enrichment of intermediate components expanded the APE, and the operating conditions of asphaltene-problematic wells could be placed inside the APE. Therefore, we concluded that the dynamic asphaltene behavior must be understood for a realistic risk evaluation in the gas-injection project.

Ready for Gas Injection: Asphaltene Risk Evaluation by Mathematical Modeling of Asphaltene-Precipitation Envelope (APE) With Integration of All Laboratory Deliverables

Summary An offshore carbonate oil field in the Arabian Gulf is exhibiting asphaltene deposition inside the tubing of production wells completed in one of two main producible limestone reservoirs. This problem significantly reduces well profitability because of production loss and frequent asphaltene-removal jobs (solvent soaking). Furthermore, future full-field enhanced-oil-recovery (EOR) development—namely gas injection—is now planned and might have a risk of enhancing the asphaltene problem. Therefore, comprehensive study has been carried out not only to establish a less-frequent and more-effective remedy than the current action but also to evaluate a future risk of gas injection. The study was initiated with careful review of the fundamental measurements of asphaltene properties collected during the 20 years of production history—saturates, aromatics, resins, and asphaltenes (SARA); asphaltene contents; and asphaltene-onset-pressure (AOP). Subsequently, the mathematical modeling analysis using those properties was incorporated into the study for better understanding/predicting of asphaltene-precipitation behavior. This paper describes the integration/optimization of the asphaltene-precipitation-envelope (APE) modeling on the basis of all available laboratory data, and consequently suggests representative APE. The APE-model validity was evaluated by comparison with actual observation data in the problematic reservoir. On the basis of the mathematical models established, several sensitivities (i.e., mixing with injection gas and blending oils produced from the two main producible reservoirs) were investigated to assess impacts of the future EOR on asphaltene risk from the subsurface and surface points of view. Several types of injection gas were examined, and their risks were compared and identified. Consequently, the surface-facility design was adequately modified and optimized in order to minimize asphaltene risk influenced by gas injection.

Prediction of asphaltene precipitation using non-isothermal compositional network model

In this paper a comprehensive flow model which incorporates compositional and non-isothermal effects is proposed to investigate asphaltene precipitation onset conditions in advanced well completions. The focus is on precipitation induced by pressure and temperature conditions, particularly in flow restrictions used in wells to delay unwanted break through of water/gas. A network model is used with a non-isothermal black oil fluid model to predict the distribution of pressure, temperature, flow rate and phase fractions in all components of the well completion. The network geometry consists of a production tubing (or liner) and an annulus between the reservoir and the tubing. This geometry will allow for flow between the annulus and the tubing through inflow control devices which are commonly used for zonal control. An asphaltene precipitation envelope is used to identify locations in the well completion at risk. Subsequently, a fully compositional and non-isothermal model is invoked at these locations. This detailed model uses a Finite Difference representation of conservation of mass, energy and momentum. Furthermore, it uses an isenthalpic pseudo-three-phase equilibrium model to predict if asphaltene precipitation actually will occur inside the restriction. A case study is presented in which the proposed model was successfully used to predict physical flow parameters and asphaltene onset conditions. It was found that asphaltene precipitation may occur in flow restriction due to large pressure drop. Furthermore, it was found that the use of isothermal modeling to predict asphaltene precipitation may lead to underestimation of the precipitation. It is concluded that the details of the well completion must be represented in the flow model since pressure and temperature may vary non-monotonically from toe to heel in advanced well completions.

Laboratory Techniques to Measure Thermodynamic Asphaltene Instability

Abstract Asphaltenes are the n-pentane or n-heptane insoluble fractions of crude oil that remain in solution under reservoir temperature and pressure conditions. They are destabilized and start to precipitate when the pressure, temperature, and/or composition changes occur during primary production. The precipitated asphaltene particles will then grow in size, and may start to deposit onto the production string and/or flowlines, causing operational problems. In this paper, our emphasis is to identify the first pressure and/or temperature conditions at which the asphaltene will start to precipitate for two reservoir oils. Four different laboratory techniques were independently used to define the onset of the asphaltene precipitation envelope. These methods are:gravimetric;acoustic resonance;light scattering; andfiltration. The gravimetric method was found to be precise, and within the accuracy of the analytical methods. However, the method was time consuming. The acoustic resonance technique (ART) was fast and less subjective, but it did not define the lower asphaltene boundary. The interpretation of the onset pressure from the near-infrared (NIR) light-scattering technique (LST) was subjective to a degree. However, the NIR response defined the upper and lower boundaries of the asphaltene envelope and the bubblepoint pressure, as did the gravimetric technique. In a manner similar to those of the gravimetric technique and LST, the filtration technique can also define the upper and lower asphaltene phase boundaries, in addition to the bubblepoint pressure. The filtration technique is fast compared to the gravimetric technique, but takes more time than the ART and LST methods. Introduction Asphaltenes remain in solution under reservoir temperature and pressure conditions. They start to precipitate when the stability of the colloidal dispersion is disturbed. This disturbance can be caused by changes in pressure, temperature, and/or composition of the oil. Precipitation and deposition of asphaltenes have reportedly caused operational problems, ranging from plugging of tubulars and flowlines(1–3) to clogging of production separators(4). Leontaritis and Mansoori present a comprehensive description of field problems caused by asphaltene deposition(5). Figure 1 schematically presents the asphaltene-related problems that may occur in the field. Asphaltene precipitation problems can be categorized as follows:Precipitation can be caused by the changes in temperature and/or pressure during primary depletion.Precipitation can be caused by blending or commingling of two noncompatible reservoir fluid streams (i.e., subsea completions), acid stimulation and/or enhanced recovery injection gases (CO2, H2S, or rich gas). The correct operating procedure to minimize the asphaltene problem is not well understood. We believe a better understanding of the fundamental processes leading to solids precipitation is a prerequisite to management and prevention of production problems. Primarily, two theoretical approaches have been presented in the literature to compute phase separations of asphaltene during primary production. These approaches include association modeling(6, 7) and calculation of asphaltene solubility parameters with the Flory Huggins polymer phase separation technique.(8, 9) Asphaltene destabilization caused by solvent injection and consequent alteration of the rock surface wettability have also been reported in the literature, but are not discussed here.(10).