Pressure Volume Temperature Research Articles

Determination of Individual Diffusion Coefficients of C3H8/n-C4H10/CO2/Heavy-Oil Systems at High Pressures and Elevated Temperatures by Dynamic Volume Analysis

SummaryBy coupling heat and mass transfer for C3H8/n-C4H10/CO2/heavy-oil systems as well as by treating heavy oil as multiple pseudocomponents, a new technique together with its computational scheme has been developed to determine individual diffusion coefficients of alkane solvents and CO2 in heavy oil at high pressures and elevated temperatures by dynamic volume analysis (DVA). Experimentally, well-designed diffusion tests have been conducted for an n-C4H10/heavy-oil system, a CO2/heavy-oil system, an n-C4H10/CO2/heavy-oil system, and a C3H8/n-C4H10/CO2/heavy-oil system by using a visualized pressure/volume/temperature (PVT) setup. The volume change of liquid phase is monitored and recorded during the measurements, whereas the gas-chromatography (GC) method is used to determine the compositions of gas mixtures at the beginning and the end of the diffusion tests. Theoretically, the volume-translated Peng-Robinson (PR) equation of state (EOS) characterizing heavy oil as multiple pseudocomponents has been incorporated to develop a 2D heat-and-mass-transfer model for the aforementioned systems. The alternating-direction-implicit algorithm is applied to solve the 2D difference equations into which a moving gas/liquid interface has been successfully incorporated. The discrepancy between the measured and calculated dynamic-volume change and the discrepancy between the measured and calculated gas compositions at the end of diffusion tests have been minimized to determine the individual diffusion coefficients. Alkane solvents diffuse faster than CO2 in heavy oil, whereas addition of alkane solvent(s) into the CO2 stream not only enhances mass transfer, but also achieves an improved swelling effect of heavy oil. Among the four diffusion tests, the largest dynamic swelling factor at the end of the diffusion test is measured to be 1.118 for the C3H8/n-C4H10/CO2/heavy-oil system.

Effect of Pore-Size Distribution on Phase Transition of Hydrocarbon Mixtures in Nanoporous Media

Summary Pore sizes of many shale-oil and tight gas reservoirs are in the range of nanometers. In these pores, capillary pressure and surface forces can make the phase behavior of hydrocarbon mixtures different from that characterized in pressure/volume/temperature (PVT) cells. Many existing phase-behavior models use a single pore size to describe the effect of confinement on phase behavior. To follow up with our earlier theoretical studies and experimental observations, this research investigates the effect of pore-size distribution. By use of a vapor/liquid equilibrium model that considers the effect of capillary pressure, we present a procedure to simulate the sequence of phase changes in a porous medium caused by a pore-size distribution. This procedure is used to simulate depressurizations of a light oil and a retrograde gas confined inside nanoporous media, the pore-size distributions of which are characteristic of tight reservoirs. The fluid compositions are representative of typical reservoir fluids. Predictions of the model show that phase transition in nanoporous medium with pore-size distribution is not described by a single phase boundary. The initial phase change in the large pores alters the composition of the remaining fluid, and, in turn, suppresses the next phase change. For the two cases studied, models with and without capillary pressure gave similar predictions. For light oil, capillary pressure still noticeably increased the level of supersaturation, and the critical gas saturation had a strong influence on the properties of produced fluids. For retrograde gas, the effect of capillary pressure was insignificant because of the low interfacial tension (IFT). Despite the choice of fluids, calculations indicate that the smallest pores are probably always occupied by hydrocarbon liquid during depressurization.

A Review and Extension of Existing Consistency Tests for PVT Data From a Laboratory

SummaryAny calculation of the phase behavior of a reservoir fluid from the reservoir to the refinery requires prior knowledge of the fluid's physical properties. Because the necessary pressure–volume–temperature (PVT) experiments are not free of systematic and random errors, the engineer involved in using fluid models is advised to check the fluid properties determined by the laboratory before application in their simulation models. This paper is designed to provide a guideline for how to obtain reliable and consistent PVT data from a laboratory. In addition, it reviews and extends existing consistency checks with a critical focus on the Y-function. Its applicability is limited to the two-phase region of a reservoir fluid. As it turns out, the Y-function can be applied not only to the constant-composition experiment (CCE) of black oil (BO), but also for the same experiment with a gas-condensate (GC). Furthermore, we show that the Y-function is a useful tool for the evaluation of the differential-liberation experiment (DLE, BO) and the constant-volume depletion (CVD, GC). In all these cases, the shape of this function is close to a straight line. After the Y-function is properly set up, it is possible to estimate the quality of the CCE and the DLE for the BO case and CCE and CVD for the GC. The second part of the review is devoted to explaining the role of the solution gas in BO, because both the formation volume factor (FVF) Bo and the oil viscosity μo are affected by the amount of solution gas. Helpful functions for estimates and consistency checks are given. In addition, estimates for the isothermal compressibility and the isobaric expansion of oil are presented.

Thermoelastic properties of grossular–andradite solid solution at high pressures and temperatures

The pressure–volume–temperature (P–V–T) equation of state (EoS) of synthetic grossular (Grs)–andradite (And) solid-solution garnet sample have been measured at high temperature up to 900 K and high pressures up to 22.75 GPa for Grs50And50, by using in situ angle-dispersive X-ray diffraction and diamond anvil cell. Analysis of room-temperature P–V data to a third-order Birch–Murnaghan (BM) EoS yields: V0 = 1706.8 ± 0.2 A3, K0 = 164 ± 2 GPa and K′0 = 4.7 ± 0.5. Fitting of our P–V–T data by means of the high-temperature third-order BM EoS gives the thermoelastic parameters: V0 = 1706.9 ± 0.2 A3, K0 = 164 ± 2 GPa, K′0 = 4.7 ± 0.2, (∂K/∂T)P = −0.018 ± 0.002 GPa K−1, and α0 = (2.94 ± 0.07) × 10−5 K−1. The results also confirm that grossular content increases the bulk modulus of the Grs-And join following a nearly ideal mixing model. The relation between bulk modulus and Grs mole fraction (XGrs) in this garnet join is derived to be K0 (GPa) = (163.7 ± 0.7) + (0.14 ± 0.02) XGrs (R2 = 0.985). Present results are also compared to previously studies determined the thermoelastic properties of Grs-And garnets.

Volumetric profile of polymer melts from the ISM equation of state

ABSTRACTKnowledge of the volumetric or pressure–volume–temperature (PVT) profile of molten polymers is important for both engineering and polymer physics. Ihm–Song–Mason (ISM) equation of state (EOS) has been employed to predict the volumetric properties of 12 molten polymers. The significance of the present paper is three temperature-dependent parameters of the ISM EOS to be determined using corresponding states correlations based on the molecular scaling constants, dispersive energy parameters between segments/monomers (ε) and segment diameter (σ) rather than bulk properties, e.g. the liquid density and temperature both at normal boiling point. The ability of the ISM EOS has been evaluated by comparing the results with 1390 literature datapoints for the specific volumes over the temperature range from 293 to 603.5 K and pressure range from 0.1 to 200 MPa. The average absolute deviation (AAD) of the calculated specific volumes from literature data was found to be 0.52%. The isothermal compressibility coefficients, κT values of molten polymers have also been predicted using the ISM EOS. From 684 datapoints examined, the AAD of estimated κT was equal to 7.55%. Our calculations on the volumetric and thermodynamic properties of studied polymers reproduce the literature data with reasonably good accuracy.

Hydrogen Bonding in Polymer Solution

The perturbed hard-sphere-chain-association (PHSC-AS) equation of state is applied to calculate the phase equilibrium of hydrogen bonding polymer systems. The pure parameters of polymers are estimated by regression of pressure–volume–temperature (PVT) data of pure molten-polymer. The calculation results show a good agreement with experimental data over the wide temperature (303 to 543 K) and pressure (1 to 2001 bar) range. The calculation results for vapor–liquid equilibrium (VLE) of polymer–solvent systems also show a good accuracy with ARD error of about 4% (a total of 354). The PHSC-AS model describes well the effects of various factors on vapor pressure of hydrogen-bonding polymer solution, such as temperature, solvents with different polarity (i.e., water, alcohols, acetone, amine), and the molecular weight and molecular structure of polymer. In addition, the infinite dilution weight fraction activity coefficient (WFAC) of strongly polar solvents such as water, alcohols, and acetic acid is calculated...

Estimation of concentration‐dependent diffusion coefficients of gases in heavy oils/bitumen using experimental pressure‐decay data

AbstractThe diffusion coefficient (D) of gases in heavy oils is an important mass transfer parameter to model and design gas injection processes for oil recovery. The pressure‐decay technique (PDT) is one of the widely used experimental methods available to infer this coefficient. PDT records the declining gas phase pressure resulting from the diffusion of gas into heavy oil inside a pressure/volume/temperature (PVT) cell. Commonly, the gas phase pressure decay is modelled by use of Fick's second law along with gas‐phase mass balance equations and assuming a constant diffusion coefficient. In this work, we evaluate two concentration‐dependent diffusion coefficient functions, power‐law and exponential. A simple history matching technique is used to estimate the apparent diffusion coefficient (Do) and concentration dependency factor (ma) from pressure‐decay data. Extensive application of our method to experimental pressure‐decay tests shows that in addition to constant diffusion coefficients, both power‐law and exponential functions are capable of predicting the experimental data. This implies that other experimental techniques are required to extract the functionality of diffusion coefficients with gas concentrations in heavy oil.

Visualization for measuring the PVT property of viscoelastic polystyrene/CO2 mixtures at elevated temperatures and pressures

Pressure-volume–temperature (PVT) data for polymer/gas solutions are fundamental to the design and control of such polymer processes as injection molding, foaming, blending and extraction reaction. Previous studies have offered methodologies based on the observation of an axisymmetric polymer pendent/sessile drop, which is used to measure the polymer's PVT behavior at elevated temperatures and pressures. Because polymer generally has high viscosity and elasticity, it is not easy to form an axisymmetric shape out of some types of polymer drops. Our study uses a novel rotational device in a high-pressure and high-temperature cell with a visualization window. This makes it possible to measure the PVT behavior of polymer/gas solutions in those cases where it is not easy to obtain an axisymmetrically-shaped polymer drop. The degree of asymmetry is mathematically defined, and an algorithm is developed to integrate the asymmetric profile for determining the PVT (that is, the volume swelling) of the polymer/gas solution. We have presented a case study on the pressure-volume-temperature (PVT) property of a polystyrene (PS)/CO2 solution at temperatures elevated in the range of 423 K–523 K and at pressures from 6.895 MPa to 27.579 MPa. We found that the volume of the asymmetric sessile drops of PS/CO2 in the PS melt determined the extent of the melt's swelling with the dissolved CO2.

The Equation of State and the Temperature, Pressure, and Shear Dependence of Viscosity for a Highly Viscous Reference Liquid, Dipentaerythritol Hexaisononanoate

Measurements are reported for dipentaerythritol hexaisononanoate (DiPEiC9) of pressure–volume–temperature (pVT) response to pressures to 400 MPa and temperatures to 100 °C, and of viscosity at pressures to 700 MPa and temperatures to 90 °C and shear stress to 18 MPa. These data complement the low-shear viscosities published by Harris to pressures to 200 MPa and the compressions by Fandiño et al. to 70 MPa. The improved Yasutomi correlation reproduces all viscosity measurements with accuracy better than the Doolittle free volume and the Bair and Casalini thermodynamic scaling models which require an equation of state (EoS). The interaction parameter for thermodynamic scaling, γ = 3.6, is less than that reported by Harris (γ = 4.2) and the difference is primarily in the choice of EoS. The shear stress at the Newtonian limit, about 6 MPa, is exceptionally large given the high molecular weight of DiPEiC9. The large Newtonian limit is also seen in the oscillatory shear response.

Experimental and Theoretical Determination of Diffusion Coefficients of CO2-Heavy Oil Systems by Coupling Heat and Mass Transfer

By treating heavy oil as multiple pseudocomponents, techniques have been developed to experimentally and theoretically determine diffusion coefficients of CO2-heavy oil systems by coupling heat and mass transfer together with consideration of swelling effect. Experimentally, diffusion tests have been conducted for hot CO2-heavy oil systems with three different temperatures under a constant pressure by using a visualized pressure-volume-temperature (PVT) setup. The swelling of liquid phase in the PVT cell is continuously monitored and recorded during the measurements. Theoretically, a two-dimensional (2D) mathematical model incorporating the volume-translated Peng–Robinson equation of state (PR EOS) with a modified alpha function has been developed to describe heat and mass transfer for hot CO2-heavy oil systems. Heavy oil sample has been characterized as three pseudocomponents for accurately quantifying phase behavior of the CO2-heavy oil systems, while the binary interaction parameters (BIPs) are tuned with the experimentally measured saturation pressures. The diffusion coefficient of hot CO2 in heavy oil is then determined once the discrepancy between the experimentally measured dynamic swelling factors and theoretically calculated ones has been minimized. During the diffusion experiments, heat transfer is found to be dominant over mass transfer at the beginning and reach its equilibrium in a shorter time; subsequently, mass transfer shows its dominant effect. The enhanced oil swelling mainly occurs during the coupled heat and mass transfer stage. CO2 diffusion coefficient in heavy oil is found to increase with temperature at a given pressure, while it can be explicitly correlated as a function of temperature.

Methodology Evaluates Artificial-Lift Requirements Amid High Uncertainty

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177436, “A Systematic, Integrated Approach To Evaluate Artificial-Lift Requirements While Dealing With High Uncertainty,” by S. Caicedo, C. Montoya, J. Abboud, and S. Tiar, Abu Dhabi Company for Onshore Petroleum Operations, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. When evaluating artificial-lift requirements, sometimes data present uncertainties at the initial planning stage. This is the case for a field that had 10 wells drilled but only four of them producing after 6 years, at which point operations were suspended. The high-level plan was to exploit and abandon the reservoir as soon as possible. This paper presents the integrated and structured methodology that was used to deal with the high-uncertainty conditions. Introduction ABC is a small field that has 10 wells, out of which only four produced from 1993 to 1999 while the remaining six were shut in after few months of production. Subsequently, the operations in ABC were suspended and the surface facilities were mothballed. Because of attractive remaining reserves along with high reservoir pressure, and considering that this field is in an urbanized area, a plan was requested that would deplete and abandon the reservoir as quickly as possible. Because of the adjusted time frame for the project, developing and planning this task required a preliminary analysis using the available data acquired during the 6 years of operation and some complementary reservoir studies. Because ABC is a complex reservoir with natural fractures and varying condensate composition, the reservoir-model uncertainties were difficult to minimize with data from only four wells and 6 years of history. Typically, artificial-lift evaluation comes after the reservoir has a good model and a defined exploitation scheme. In this case, the selection of the artificial-lift method dealt with high data uncertainty associated with reservoir pressure, gas/oil ratio (GOR), and water-cut profiles because of the reservoir’s complexity and pressure/volume/temperature (PVT) properties. To overcome the uncertainty and advance the study concurrently with an ongoing reservoir- simulation study, the following approach was adopted: Understand and demonstrate how uncertainty in ABC affects artificial-lift selection. Perform a preliminary artificial-lift- method screening for a matrix covering a range of reservoir pressures, GORs, water cuts, and wellhead pressures in order to discard some methods and focus on possible solutions. Build a matrix to determine the conditions under which the wells flow naturally and those under which artificial lift is required. Determine the probability of the scenarios in relation to the results of reservoir-simulation work.

Practical Considerations for Well Performance Analysis and Forecasting in Shale Plays

Analysis and forecasting of well performance data in unconventional reservoirs is and will likely remain problematic as there is considerable uncertainty related to our current lack of understanding of the fluid flow phenomenon in low/ultra-low permeability reservoir systems.There are many unknowns which are the primary sources of the uncertainty on production performance.To name a few, these can be stated as the link between flow in nano scale and macro scale, effect of natural fractures and stress fields/geomechanics, pressure/stress dependent dynamic reservoir properties (e.g., permeability), Pressure-volume-temperature (PVT) properties at nano scale, extent of drainage area, etc. Recently, a great amount of research has been performed to understand and relate these issues to well performance analysis and forecasting, but still no conclusive answer has been provided.The objective of this paper is to briefly discuss the specifics of flow in low permeability systems and models to represent well performance then present a methodology to analyze and forecast production data.

Microfluidic PVT--Saturation Pressure and Phase-Volume Measurement of Black Oils

Summary In this work, we present a small-scale pressure/volume/temperature (PVT) cell that allows for the measurement of saturation pressure and phase-volume ratio by use of only a few microliters of black-oil samples. This novel PVT measurement technique has been successfully tested on live samples at elevated pressure (86 MPa) and temperature (150°C). In the microfluidic PVT platform, the small microfluidic device performs the same function as the laboratory-scale pressurized visual PVT cell. At the heart of the microfluidic device, is a long and narrow capillary, densely packed in a serpentine shape, embedded on the device. The capillary is nearly 1 m long and has a total volume of 5 µL. The microfluidic device is fabricated with glass and silicon, which allow visual monitoring of a fluid sample at various pressures and temperatures. To acquire PVT data, the pressure in the capillary is systematically reduced to accurately detect the appearance of micron-sized gas bubbles in a sample at saturation pressure. Because of the small thermal mass of the device, the temperature of the sample can be changed rapidly, which enables the measurement of multiple saturation pressures in quick succession. Below the saturation pressure, the growing gas bubbles form a segmented gas/liquid distribution in the capillary. The lengths of the liquid and gas segments are measured in real-time with an automated image-capturing and analysis tool to determine the gas/liquid phase-volume ratio at a given pressure. Validation tests have proved this technique to be repeatable and feasible for rapid PVT measurements of black oils [gas/oil ratio (GOR) ranging from 102 to 143 m3/m3]. The results presented in this study demonstrate that the microfluidic PVT system can measure saturation pressure and phase-volume with data quality comparable to that of the conventional PVT method, however, with significantly smaller sample volume and faster turnaround. The microfluidic PVT system is demonstrated to have the potential to become a reliable and portable measurement platform.

Adaptive Local-Global Multiscale Simulation of the In-situ Conversion Process

Summary Numerical modeling of the in-situ conversion process (ICP) is a challenging endeavor involving thermal multiphase flow, compositional pressure/volume/temperature (PVT) behavior, and chemical reactions that convert solid kerogen into light hydrocarbons and are tightly coupled to temperature propagation. Our investigations of grid-resolution effects on the accuracy and performance of ICP simulations demonstrated that ICP-simulation outcomes (e.g., oil/gas production rates and cumulative volumes) may exhibit relatively large errors on coarse grids, where “coarse” means a gridblock size of more than 3 to 5 m. On the other hand, coarse-scale models are attractive because they deliver favorable computational performance, especially for optimization and uncertainty quantification workflows that demand a large number of simulations. Furthermore, field-scale models become unmanageably large if gridblock sizes of 3 to 5 m or less have to be used. Therefore, there is a clear business need to accelerate the ICP simulations with minimal compromise of accuracy. We developed a novel multiscale-modeling method for ICP that reduces numerical-modeling errors and approximates the fine-scale simulation results on relatively coarse grids. The method uses a two-scale adaptive local-global solution technique. One global coarse-scale and multiple local fine-scale near-heater models are timestepped in a sequentially coupled fashion. At a given global timestep, the global-model solution provides accurate boundary conditions to the local near-heater models. These boundary conditions account for the global characteristics of the thermal-reactive flow and transport phenomena. In turn, fine-scale information about heater responses is upscaled from the local models, and used in the global coarse-scale model. These flow-based effective properties correct the thermal-reactive flow and transport in the global model either explicitly, by updating relevant coarse-grid properties for the next timestep, or implicitly, by repeatedly updating the properties through a convergent iterative scheme. Upon convergence, global coarse-scale and local fine-scale solutions are compatible with each other. We demonstrate the much-improved accuracy and efficiency delivered by the multiscale method by use of a 2D cross-section pattern-scale ICP simulation problem. The following conclusions are reached through numerical testing: (1) The multiscale method significantly improves the accuracy of the simulation results over conventionally upscaled models. The method is particularly effective in correcting the global coarse-scale model through the use of the fine-scale information about heater temperatures to regulate the heat-injection rate into the formation more accurately. The effective coarse-grid properties computed by the multiscale method at every timestep also enhance the accuracy of the ICP simulations, as demonstrated in a dedicated test case, in which a constant heat-injection rate is enforced across models of all investigated resolutions. (2) Multiscale ICP models result in accelerated simulations with a speed-up of four to 16 times with respect to fine-scale models “out of the box” without any special optimization effort. (3) Our multiscale method delivers high-resolution solutions in the vicinity of the heaters at a reduced computational cost. These fine-scale solutions can be used to better understand the evolution of the fluids and solids (e.g., kerogen conversion and coke deposition) in the vicinity of the heaters (several-feet-long spatial scale). Simultaneously, with the fine-scale near-heater solutions, the local-global coupled multiscale model provides key commercial ICP performance indicators at the pattern scale (several-hundred-feet-long spatial scale) such as production functions.

Acoustic Velocity Measurements and Interpretation for Challenging Fluid Systems

Summary In terms of experimentation, acoustic velocity can be measured with a high degree of accuracy. Several thermodynamic properties related to acoustic velocity such as density, isothermal compressibility, and heat capacity can be extracted from measured data. In this study, technical improvements are implemented in an effort to develop a technique for fast and reliable determination of fluid properties on the basis of acoustic velocity measurements over an expanded range of pressures. The potential use of this device as a quality-control tool in typical pressure/volume/temperature (PVT) measurements is demonstrated. Baseline measurements matched to published literature verify the suitability of the device. Results of tests on three recombined oil samples containing dissolved gas, with prescribed gas/oil ratios (GORs), and one bitumen sample are presented. A sharp change in the acoustic velocity trend near the gas/liquid-saturation point is evidence of gas evolution during depressurization. Strong attenuation complicates measurement of acoustic velocity on the heavy fluids used in this study. Blending bitumen with a midrange-molecular-weight hydrocarbon mixture enables estimation of the undiluted-fluid acoustic velocity by extrapolation. By use of the measured acoustic velocity data available, a methodology is developed to estimate and quality check measured isothermal compressibility (κT) values. This is especially important for low-compressibility systems. Heat-capacity data for simple alkanes (CH4 to n-C10) and toluene helps to define a reasonable range of heat-capacity ratio (γ) expected for typical reservoir fluids. For the typical values of acoustic velocity encountered in the pressure and temperature range of interest, the isothermal compressibility can be calculated and/or quality checked by use of estimated values of γ. In addition, by use of various data sets and by performing graphical error analysis, we have shown the reasons that the methodology works. Available data for n-decane and n-hexadecane along with measured data for a live oil and numerical work on calibrated data sets in this study are used to develop the methodology.

New insights into the formation mechanism of high hydrogen sulfide–bearing gas condensates: Case study of Lower Ordovician dolomite reservoirs in the Tazhong uplift, Tarim Basin

Huge, high gas–oil ratio, hydrogen sulfide (H2S)-bearing gas condensate accumulations were recently discovered in the Ordovician carbonate reservoirs of the Tazhong uplift in the Tarim Basin, northwest China. Distinct differences exist between the eastern and western condensates in terms of chemical and isotopic compositions. Condensates from the western part of the uplift were characterized by high dibenzothiophenes (generally >500 μg/g), a high H2S concentration (∼7%, vol./vol.), and relatively depleted 13C methane (δ13C1 = −55.5‰ to −36‰). The H2S concentration in the Tazhong gas condensates shows a positive correlation to Mg2+ concentration in the formation water. Formation water in Lower Ordovician–Cambrian strata in the Tazhong uplift is rich in Mg2+, which facilitates the thermochemical sulfate reduction (TSR) of sulfate contact ion pairs (CIPs) to produce H2S and dibenzothiophenes. A detailed comparison of the chemical compositions of the formation waters in different strata indicates that a high H2S concentration in the Tazhong gas condensates originates from the TSR of sulfate CIPs in the Lower Ordovician–Cambrian strata, where a primary oil accumulation may have existed. The concentrations of 3- and 4-methyldiamantanes in the western condensates (80 to 150 μg/g) are relatively lower than those from the eastern part of the uplift. Also, the δ13C1 in the western H2S-bearing gas condensates was more negative, and the δ13C2 − δ13C1 value was larger than that from typical TSR-altered gases. These features indicate that the western Tazhong samples had just entered the initial stage of TSR. According to the pressure, volume, temperature (PVT) phase diagram, the lower Paleozoic section was quickly buried after the Tortonian. High-H2S hydrocarbon inclusions formed during the last 10 m.y. when paleotemperatures reached 140°C (284°F). Because the reaction rate of the sulfate CIPs oxidation was relatively slower than that of H2S autocatalysis during the entire TSR process, advanced TSR has not been accomplished yet. It is also inferred that the Tortonian was the key period for accumulation of secondary H2S-bearing gas condensates, resulting from abundant gas washing along deep fractures and charging in the early reservoirs. An increased aromaticity parameter (toluene/n-heptane) and an increased fractionation index from east to west indicate an intensified degree of gas washing. Different gas-washing intensities in the eastern and western gas condensates led to diverse PVT states as well. Deep strata in the Tazhong uplift were characterized by multiple charges and mixing, coupled with periodic TSR, leading to the occurrence of variable H2S-bearing gas condensates.

Molecular dynamics analysis of compositional effects in hydrocarbon systems property calculations

Fluid pressure–volume–temperature (PVT) properties are essential for enhanced oil recovery (EOR) process description, particularly for the development of new recovery processes such as solvent injection. However there remains significant uncertainty in laboratory experimental data, such as that associated with light and heavier components mixing processes. Much of this uncertainty may be attributed to the multicomponent nature of most oils and the existence of micro-structures in real dynamic systems.Here, an alternate engineering approach is proposed and illustrated to obtaining this required data, which can be used as an alternative to, or in conjunction with, expensive and time-consuming direct experimental measurements. This method utilizes the molecular dynamics (MD) method to setup dynamic simulation models for a variety of hydrocarbon systems. More particularly, 16 single phase (both single and multicomponent) MD hydrocarbon systems are considered, as well as 3 biphasic (methane–decane) MD systems to quantify aspects of dynamic mixing. The impact of a variety of oil chemical structures (normal and branched alkanes, cycloalkanes, aromatic, and polar) on fluid property predictions is thereby highlighted, with implications for future additional complex oils analysis.With these systems, a large range of equilibrium and non-equilibrium properties under different T, P and compositional scenarios have been predicted, and good agreement with available laboratory experimental data has been demonstrated here. Indications of subtle microstructure phenomena are also obtained from our MD analysis. As the resultant MD data represent many years of costly experimental measurements, this points to a new cost-efficient approach in obtaining necessary EOR parameters, to be used in conjunction with limited targeted experiments.

Forecasting density, oil formation volume factor and bubble point pressure of crude oil systems based on nonlinear system identification approach

Accurate predictions of fluid properties, such as density, oil formation volume factor and bubble point pressure, are essentials for all reservoir engineering calculations. In this paper, an approach based on nonlinear system identification modeling; Nonlinear ARX (NARX) and Hammerstein-Wiener (HW) predictive model, is proposed for forecasting the pressure/volume/temperature (PVT) properties of crude oil systems. To this end, two datasets; one containing 168 PVT samples from different Iranian oil reservoirs and other a databank containing 755 data from various geographical locations, were employed to construct (i.e. train) and evaluate (i.e. test) the models. Simulation results demonstrate that the proposed NARX and HW models outperform previously employed methods including three types of artificial neural networks models (committee machine, multilayer perceptron and radial basis function), two types of ANFIS models (grid partition and fuzzy c-mean) and several empirical correlations with the smallest prediction error, and that they are reliable models for predicting the oil properties in reservoirs engineering among other soft computing approaches.

The application of modified PVT data on the warpage prediction of injection molded part

The warpage of injection molded part strongly depends on the shrinkage property, which is highly dominant by the Pressure-Volume-Temperature (PVT) curves. Accurate description of PVT curves is essential for running the simulation of warpage. The standard PVT curves are measured at different pressure for the isotactic polypropylene, which are modified with the help of crystallizing curves obtained by the Differential Scanning Calorimetry (DSC) tests at different cooling rate. The user subroutine UEXPAN is coded to describe the modified PVT curves and implemented into the FEA model for warpage prediction in Abaqus. The simulated deflection of a plaque is performed and compared with the one measured by the coordinate measuring machine (CMM). It is concluded that the specific volume at high cooling rate varies slower with the temperature than that at low cooling rate and thus the predicted deflection with modified PVT data decreases significantly with increasing cooling rate. This numerical observation matches well with the experimental result. The warpage decreases when the crystallinity increases from 33 to 60 %. The plaque has the lowest peak deflection when the cooling rate is 60 °C/min. The system is built successfully for the warpage prediction of injection molded part.

Sensitivity analysis on sampling from affected wells by gas coning

ABSTRACTOnly representative samples could represent original reservoir conditions and have prevented overdesigning surface facilities and have been requirements of reservoir management programs. Representative samples cannot be collected in unsteady state situations. In some cases, samples must be collected in this state, so non-representative samples are obtained. Gas coning is one of the parameters that makes unsteady state flows. There is no standard method to determine accurate original compositions from non-representative samples. In this article, an attempt is made to introduce an accurate method for obtaining original in situ compositions from gas coning wells. Four Iranian oil reservoir samples obtained from the pressure volume temperature laboratory are used for evaluating methods of obtaining original fluids in unsteady state situations for the first time. For this purpose a synthetic model is formed by compositional simulation, and fluid properties of each reservoir are imported to it. Separator sampling is performed in the model. Methods of synthesizing original compositions (recombination and equilibrium contact mixing) are modeled by detailed equation of state characterization in the new scheme. Then collected samples are imported to them. Comparisons are made on obtained results of recombination and equilibrium contact mixing methods to find the most accurate method. It is concluded that equilibrium contact mixing, which was uncertain for companies, is definitely the most accurate method. Also, the authors conclude that after more than 2 years production performing an equilibrium contact mixing method is impossible in volatile oil models with gas coning but recombination with low accuracy can be used; however, equilibrium contact mixing has no limitation in black oil systems with gas coning and has minimum errors.