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Abstract The incompatibility of injected saline seawater and formation water is the primary cause of scale deposition in offshore developments. Many offshore oilfields are encountering problems with barium sulfate precipitation due to the mixing of sulfate-anion-rich seawater and formation brine with excessive amounts of barium cation. A mechanistic physico-chemical modeling approach is required to predict the amount of scaling to assist operators in making decision regarding scale prevention in oil reservoirs. The predictive model allows various types of flow scenarios to be investigated to reduce the amount of scaling and prevent well damage and eventual loss of well productivities. Three-dimensional field-scale simulations were performed to investigate the flow and transport of barium and sulfate ions and the significance of barium sulfate precipitation in a typical offshore oil reservoir. The reservoir simulator has the modeling capability of multiphase flow, water reaction chemistry and interaction with the rock, and more significantly the species transport equations that include physical dispersion. The reactions were kept simple with barium and sulfate ions as the only reacting species and sodium, chloride, and calcium ions as non-reacting species. Barium sulfate was considered as the only solid precipitate. Simulations were performed to determine sensitivity to dispersion and mixing in the reservoir, to determine how much solid precipitates in the reservoir and in the wellbore, and to estimate how much sulfate needs to be removed from the injected seawater to prevent the formation damage. Introduction Barium sulfate and related scale occurrences are considered serious problems that cause formation damage and loss of productivity near production wellbores. Sulfate scales may result from changes in temperature and/or pressure but the major cause of sulfate scaling is chemical incompatibility between the injected seawater with high sulfate ion concentrations and the formation water, which originally contains high concentrations of barium, calcium, and strontium ions. Yuan and Todd developed a model to predict the sulfate scaling problems due to chemically incompatible waters as well as by temperature and pressure changes. The model is based on solubility prediction and the sulfates' precipitation/dissolution reactions involving sulfate, calcium, barium and strontium ions. The scale predictive model uses an iterative process to meet the competitive coprecipitation of BaSO4, SrSO4, and CaSO4. The results indicated that an increase in temperature lowers the BaSO4 scaling tendency but increases SrSO4 and CaSO4 scaling tendency. The pressure increase universally makes the sulfates more soluble and therefore less prone to scaling. The model developed helps determine the type and maximum quantity of scaling that could form from a solution, but a reservoir simulation model is required to give the scaling rate and distribution in the reservoir. A method of characteristic model was developed by Araque-Martinez and Lake that included kinetics as well as equilibrium reactions to predict the well impairment. This model, however, is appropriate only for near injection wellbore calculations and does not include physical dispersion. Rocha and coworkers have developed a salt precipitation finite element numerical model that is coupled with ion transport equations to predict the amount of precipitates around the wellbore. Although the ion transport equations include the tensor diffusion, the model is developed for single-phase water flow only. Usual chemical treatments may not work for severe cases of BaSO4 scaling and treatment of the seawater to reduce the sulfate content seems more promising in some cases. Desulfurization of the seawater was considered in this paper and simulations were performed to decide how much sulfate would have to be removed from the seawater to prevent precipitation completely.
- Geology > Mineral > Sulfate (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.81)
Abstract Conventional, carbon number compositional analysis techniques provide the weight or mole fraction of pure components up to C6- and carbon number pseudo-components that represent the C7+ fraction. These typically reported carbon number oil compositions cannot be used with asphaltene and/or wax phase behavior models and are not suitable for interpretation of experimental asphaltene and wax studies, because they do not provide direct phase compositional information on the waxes, resins, and asphaltenes. Waxes, resins, and asphaltenes are usually distributed among the heavier carbon number pseudo-components in these carbon number-type compositional analyses. Hence, new techniques and methodologies are required for analyzing hydrocarbon fluids for the amount and type of waxes, resins, and asphaltenes and for developing EOS oil characterizations suitable for predicting PVT, wax, and asphaltene phenomena. This will eliminate the traditional guess-work that is involved in the development of EOS oil characterizations of asphaltenic and/or waxy fluids. A new, efficient, and more accurate technique for analyzing crude oil and its fractions to determine hydrocarbon group types, i.e., paraffins (including paraffin waxes), aromatics, resins, and asphaltenes is the PARA analysis. Distillation, solvent extraction, high performance liquid chromatography (HPLC), gel permeation chromatography (GPC), and other techniques are used to perform the oil analyses and obtain the compositional and structural data required for characterizing each hydrocarbon group with its individual pseudocomponents. The analyses. in addition to providing weight and/or mole percent for each fraction, provides a starting a priori oil characterization suitable for EOS type modeling methods. The starting oil characterization includes an experimentally assisted selection of pseudo-components for each hydrocarbon group type together with an initial estimate of their critical properties, molecular weight, and acentric factor. This paper discusses the PARA-Based (Paraffin-Aromatic-Resin-Asphaltene) EOS reservoir fluid characterization technique and presents an example application of PVT and wax phase behavior modeling. Equation of State (EOS) Approach - Background An equation of state is a thermodynamic relation or function involving the measurable thermodynamic variables P, T,. This section gives a brief description of equations of state. Origin of Equations of State. In the field of hydrocarbon thermodynamics it has been assumed that we deal with "simple compressible substances." For these substances, the only important (i.e., of significant magnitude) reversible work mode is by volume change (Pd work). The state postulate of thermodynamics says that: The number of independently variable thermodynamic properties for a specified system is equal to the number of relevant reversible work modes plus one. This means that in hydrocarbon systems, if two thermodynamic properties are specified, the state of the system is completely specified. That is, all the other thermodynamic properties are specified as well. Mathematically, this is shown as: (1) If two of the properties of a simple compressible substance are specified. then the third can be calculated from Eq. 1. Eq. 1 is therefore called an equation of state. The simplest P- -T EOS is that of the ideal gas. (2) A gas is ideal if its molecules occupy no volume and do not interact with each other. This is clearly not true for real gases but the ideal gas law has served us well over the years in many areas of endeavor. On the basis of molecular arguments, to account for molecular volume and interaction, van der Waals, in 1983, proposed the following P- -T EOS as a modification to the ideal gas law of Eq. 2. (3) P. 421^
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract This paper examines the performance of methodologies and computational tools commonly used in the prediction of phase equilibria of mixtures in typical temperature and pressure range, at hyperbaric conditions. VLE and PVT data of binary and synthetic multicomponent mixtures up to 2000 bar are used. Correlated and prediction results are presented with the translated Peng-Robinson (t-mPR) EoS and EoS/GE models. Correlation of high pressure VLE data is possible with one kij value for systems where Tc, Pc and experimental values are available. Predicted kij values for high asymmetric systems with hydrocarbons of Nc>20 are totally unacceptable at high pressure region. There is a great uncertainty on the critical properties and the acentric factor of hydrocarbons with Nc>20 and the relative importance of these parameters is very significant at high pressure conditions. Volume translation is essential for PVT predictions. Temperature independent correlations give very satisfactory results. LCVM, although it provides the best results of the EoS/GE models studied, suffers at high pressures. Introduction In the last few years as higher depths are explored by drilling, wider ranges of temperature (up to 250 C) and pressure (up to 1200 bar) are met in practice. Reservoir fluids at such conditions are commonly referred to as hyperbaric fluids. They consist of methane (greater than 40% in mole fraction) and high amounts of heavy hydrocarbons mainly n-alkanes. They exhibit gas condensate behavior at high temperatures but they can become oils at moderate ones because of the presence of heavier compounds. Some of these methane-rich fluids are near critical as well. Crystallization of heavy hydrocarbons have also been observed for temperatures 10-30 C lower than the pure component melting temperature. These characteristics cause a significant difficulty in studying their thermodynamic behavior, both from an experimental or from a theoretical point of view. Such mixtures have not been extensively studied in the literature and experimental data at such conditions is very limited. The objective of this work is the examination of the applicability of the models used for low pressure reservoir fluids, at hyperbaric conditions and the identification of the problems encountered in the VLE and PVT calculations. Methodology The modified and translated Peng-Robinson EoS (t-mPR) as well as three predictive EoS/GE models (MHV2, PSRK and LCVM) are used to investigate the limits of our expectations in the quality of the predictions. The applied methodology consists of the followings: VLE predictions. For systems including high molecular weight compounds such as nC24 and nC36, different methods of evaluating the critical properties and the acentric factor were tested as shown in Table 1. kij values between C1/HC pairs derived from generalized correlations or from high pressure VLE data have been utilized. PVT predictions. The effect of three different approaches in the evaluation of the volume translation (t) has been examined. Table 2 presents the values used. One-parameter and multiparameter tuning has been applied to investigate possible improvement of the obtained results. Vapor-Liquid Equilibria Table 3 presents the results for the systems under study. Correlations with kij values appear satisfactory at high pressure. LCVM provides good results even at very high pressures of N2/C14 system but MHV2 and PSRK EoS/GE models fail, especially at high asymmetric systems. P. 729^
Empirical PVT Correlations Applied to Egyptian Crude Oils Exemplify Significance of Using Regional Correlations
Hanafy, H.H. (Gulf of Suez Petroleum Company) | Macary, S.M. (Egyptian Petroleum Research Institute) | ElNady, Y.M. (Al Azhar University) | Bayomi, A.A. (Al Azhar University) | El Batanony, M.H. (Egyptian Petroleum Research Institute)
H.H. Hanafy, SPE, Gulf of Suez Petroleum Company, S.M. Macary, Egyptian Petroleum Research Institute, Y.M. ElNady, SPE, Al Azhar University, A.A. Bayomi, SPE, Al Azhar University, and M.H. El Batanony, Egyptian Petroleum Research Institute Copyright 1997, Society of Petroleum Engineers, Inc. Abstract An accurate description of physical properties for crude oils is necessary for solving many of reservoir engineering and surface production operational problems. Ideally, crude oil properties are determined experimentally in the laboratory on actual fluid samples. However, in the absence of experimentally measured crude oil properties, one can resort to empirical PVT correlations. The purpose of this paper is to evaluate most of the empirically derived PVT correlations found in the literature during the last five decades by applying them to the Egyptian Crude Oils. The PVT measurements of 324 fluid samples covering a wide range of crude oils ranging from heavy to volatile oils have been used in this study. These samples were collected from 75 fields distributed along three different regions of Egypt including, the Gulf of Suez, Western Desert, and Sinai. In order to have a fair evaluation of the different correlations, special care was given to the limitations of data and nature of parameters used to derive these correlations. The results of this study were also compared with the results of similar studies performed on Egyptian oils as well as crude oils from other regions worldwide. Because the total separator gas-oil ratio is the key parameter to estimate the reservoir oil properties from most of the popular empirical correlations, this paper presents a new approach to correct the primary stage separator gas-oil ratio to estimate the total gas-oil ratio using the data base available for Egyptian oils. This paper concludes that due to regional ranges in crude oil compositions, a universal correlation that can be applied to different types of crude oils would be difficult to obtain. Therefore, correlations for a local region, where crude oil properties are expected to be uniform, would be a necessary alternative. Introduction The reservoir fluid data have many applications in different areas of the exploration and production process. While reservoir engineers generally have the greatest claim on such data, reservoir fluid analyses are also quite valuable to geologists and production specialists. One can resort to empirical PVT correlations to estimate the reservoir fluid data in the following cases:inability to obtain a representative sample, sample volume is insufficient to obtain a complete analysis, collected sample is nonrepresentative, quality check lab analysis, lab analyses are in error, estimating the potential reserves to be found in an exploration prospects, evaluating the original oil in place and reserve for a newly discovered area before obtaining the laboratory analysis to justify a primary development plan. This study evaluates the accuracy of the empirically derived PVT correlations relative to the experimental PVT for 324 Egyptian oil samples taken from 123 reservoirs in 75 fields. Table 1 presents the PVT data range for the available samples. The tested Correlations are used to estimate the bubblepoint pressure, oil formation volume factor, isothermal oil compressibility, oil density, and oil viscosity. Before measuring the accuracy of different correlations, it should be pointed out that the effective use of the correlations lies in an understanding of their development and knowledge of their limitations. Correlations Development and limitations Sutton and Farshad presented a detailed review about the development and limitations of the most widely used correlations. P. 733
- North America > United States (1.00)
- Africa > Middle East > Egypt (0.90)
- Asia > Middle East > Saudi Arabia (0.55)
Abstract Future oil and gas discoveries will be, increasingly, produced through multiphase flowlines from remote satellite facilities in deepwater environments. Much of the technology needed to design and install these facilities exists. However, our current inability to reliably predict and control the behaviour of the fluids could result in plugged lines and premature abandonments. This has lead to the high levels of conservatism seen in current designs and could ultimately result in some field deferral. Through unprecedented industry co-operation in areas such as wax and hydrates, significant progress has been made in both their prediction and control. To meet future challenges we will need to develop new predictive tools and different ways of working. Cost effective solutions will not just rely upon ongoing chemical cures but must be linked to design. "Fast track" developments have lead the way with new technologies readily being applied. This has been achieved through improved working relationships within the project design teams, with facility and production engineers working closely with production chemists, fluid specialists and reservoir engineers to "get it right first time". This paper sets out to review current and future production challenges, technical progress to date and to identify areas where further effort is required. Introduction The design strategy of most new oil/condensate discoveries has been governed predominately by reserves, reservoir performance, environment (i.e. subsea vs. onshore) and the pay-back period. However, as new discoveries are increasingly in hostile environments especially deepwater, and new technologies such as subsea completions make marginal fields more attractive, another factor "Flow Assurance" or operability is impacting design. Here the ability of the produced fluids to present a multitude of problems, from minor upsets to major shutdowns or even early abandonment, is being addressed at the design stage. Until recently traditional designs afforded us the luxury of easy access to wellheads and both ends of flow/pipelines. If the fluids presented production problems such as waxes or scales, intervention remediation was relatively easy and cost effective to achieve. As we move into remote subsea production, access into the system will become increasingly expensive and hence limited. The combination of multiphase flow and limited remediation now makes it necessary for us to have a detailed understanding of how the fluids will behave in our production system. The risks associated with not understanding fluid behaviour and its impact on system operability have all too painfully been demonstrated through flowline replacements and even early abandonments. It is through these bad experiences that the "scare factor" associated with produced fluid problems results in the high level of conservatism in design. Systems are therefore designed to either totally avoid potential fluid problems through super insulation for example, or to give us the ability to reliable intervene on a regular basis such as using round trip pigs or Through Flowline tools (TFL). Both the conservatism and potential for lost production and reserves have substantial cost implications, that, in the current economic climate we can ill afford. In order to achieve our design goals of a cost effective fit for purpose system we must be able to reliably predict and control our fluids behaviour over the production lifetime. Produced Fluid Issues The use of multiphase systems to produce and transport fluids long distances is becoming increasingly common. The fluids, a combination of gas, oil/condensate and water together with solids such as scales and sand, have the potential to cause many problems including: P. 267^
- Europe (0.70)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- (5 more...)
Abstract Determination of interfacial tension (IFT) is of importance for understanding oil recovery mechanisms. Pendant drop measurement for IFT determination is an important practical technique since it permits continuous study of interfacial phenomena without mechanical interference that occurs when other techniques are used. In application of the pendant drop technique, several methods, such as shape factor method and regression method, have been developed by previous investigators for extracting IFT information from the shape of pendant drops. It is generally recognized that some of these methods are accurate but time consuming due to a great deal of numerical computations; while others are simplified and easy to use but unfortunately inaccurate in the low IFT region. It is highly desirable to develop a simple and accurate calculation method to determine low IFT from pendant drop measurements. As IFT gets lower, pendant drops tend to be small and flat. In this case the existing methods are difficult to apply because the upper portion of the pendant drop is strongly affected by the presence of the tip and its wetting behavior. We developed a new method for IFT determination on the basis of force balance on the lower half of the pendant drop. A simple equation relating the IFT, fluid densities, and drop geometry was formulated. With known profile data of the lower half of the pendant drop, IFT can be calculated quickly from the simple equation. Like some existing methods, this new method requires high quality drop-profile data near the apex of the drop to determine the total curvature of the drop surface at the apex. Unfortunately, this high quality data is usually not available due to the nature of image digitizing. We solved this problem by digitizing rotated drop images, fitting a smoothing spline to the drop profile data, and differentiating this smoothed spline in curvature calculations. The result of IFT determined using this new method was compared with that given by other methods for water, normal decane, decyl alcohol, 2,2,4 trimethyl pentane, normal heptane, hexadecane and toluene under ambient conditions. This comparison shows a consistency among the methods in the high IFT region (IFT >10 mN/m). Using our pendant drop generating apparatus and image processing system, we tested the new method under various conditions for water, normal decane, ethane, and carbon dioxide (CO2). We found the new method more accurate than the shape factor method in the low IFT region (IFT <1 mN/m). This is because the new method allows calculation of IFT from very small droplets as long as the droplets have equators developed. Introduction Determination of IFT is of importance in various lines of chemistry, chemical engineering and petroleum engineering. Many techniques of IFT measurement are currently used at different conditions. Detachment techniques, such as Du Nouy ring and Wilhelmy slide, rely on the condition of perfect wetting of the withdrawing surface. Capillary rise, maximum bubble pressure, and drop weight techniques require calibration with liquids of known IFT. They also involve a three phase contact which introduces systematic error. The spinning drop technique is not easy to use for high temperature and pressure applications. Although Laser-Light-Scattering has been used successfully in IFT measurement, it involves systematic error with a high pressure cell where it is not practical for a diffraction grating to be located very close to the liquid surface. The traditional pendant/sessile drop technique, which is not affected by a three phase boundary, has been revived by the advances in digital video and image analysis. The principle of the pendant drop technique relies on measurement of the coordinates of an axisymmetric shaped drop and its match to the solution of the Laplace equation. All the information on the value of the IFT is contained in the shape assumed by the drop. Our literature survey indicates that six calculation methods have been developed to extract IFT information from the drop shape in the past six decades: P. 59