PVT Model Research Articles

Phase behavior experiments and PVT modeling of DME-brine-crude oil mixtures based on Huron-Vidal mixing rules for EOR applications

We present extensive experimental and modeling studies on phase behavior of DME-brine-crude oil mixtures using the Peng–Robinson equation of state (EOS) with the Huron-Vidal mixing rule to capture the interaction between various components of the mixture. We show that DME has strong preference towards the oil phase as compared to the aqueous phase due to its first contact miscibility with hydrocarbons and partial solubility in water/brine. This feature makes DME a potential candidate for enhanced oil recovery (EOR) applications that can lead to accelerated oil production compared to conventional waterflooding technologies. In particular, we present novel experimental data for (i) solubility of DME in brine at various conditions of pressure, temperature and salinity; (ii) phase behavior of a live crude oil; and (iii) partitioning of DME between brine and the live crude oil at reservoir condition. We also develop a PVT model for the DME-brine-oil mixture based on experimental data available from combination of in-house measurements and literature data. Finally, we investigate the predicting capability of the tuned PVT model and determine the effect of feed composition on DME-partitioning coefficients.

Bubble Point Simulation of Reservoir Oil and Carbon Dioxide Mixtures

Accurate knowledge of the multicomponent phase behavior of carbon dioxide (\(\hbox {CO}_2\)) with hydrocarbon fluids is needed in the design, operation and development of carbon dioxide-based enhanced oil recovery (EOR) techniques, in particular, understanding the phase behavior of \(\hbox {CO}_2\) and hydrocarbon fluids system. In recent years, the possibility of sequestering \(\hbox {CO}_2\) (a greenhouse gas) in underground (oil) reservoirs has been proposed. The feasibility will also be affected by the phase behavior of \(\hbox {CO}_2\) in the presence of chemical species present in the reservoirs (Al-Marri in PVT, phase behavior and viscosity measurements and modeling of the ternary and binary systems of carbon dioxide \(+\) heavy hydrocarbon (n-eicosane) \(+\) light gas (ethane or propane), Ph.D. Thesis, University of Southern California, 2006). PVT viscosity and vapor–liquid equilibria are important in EOR process, reservoir simulations and process design. Phase behavior consists of two parts, in the first part the recombination process takes place by inserting the data of surface fluids into the PVT simulation to determine various fluid properties and especially the bubble point at reservoir temperature. In the second part, the swelling test is introduced by inserting the data of carbon dioxide (99.6% purity) as injection fluid into the recombined fluid to investigate the swelling factors. The modified Peng–Robinson equation of state was used for predicting saturation pressure. For fluid mixtures, the Van Der Waals mixing rules are commonly used. Results of the simulation were compared with the experimental data showing that the saturation pressure of the recombined fluid/\(\hbox {CO}_2\) system was strongly affected by the concentration of carbon dioxide. Thus, this enhanced the oil recovery from heavy oil reservoirs.

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

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

Theoretical modeling for thermophysical properties of cellulose: pressure/volume/temperature data

Thermo-compression process—compression of pure cellulose under high temperatures and pressures—is a recent method to produce biodegradable materials. For such processes, experimental measurements and study of properties and behavior of cellulose are difficult to carry out. To overcome these difficulties, a complete pressure–volume–temperature investigation is needed as carried out in this work. To develop a predictive thermodynamic PVT model of cellulose theoretically, the modified Sanchez and Lacombe equation of state together with the implementation of the Hoftyzer and van Krevelen group contribution method and the Boudouris modification to the Constantinou and Gani’s group contribution method were coupled to the Compressible Regular Solution theory. The developed method is a pure predictive model and to examine the accuracy of theoretically calculated PVT data by the model, some available PVT data of cellulose at temperatures from 25 to 180 °C and pressures from 19.6 to 196 MPa (219 data points) were collected from literature. The comparisons were made and the agreement between the calculations and the experimental data were acceptable with a Cumulative Absolute Relative Deviation of 0.04 %. Consequently, the model can be used for prediction of thermodynamic properties of cellulose and cellulose-containing mixtures.

PVT correlations for Pakistani crude oils using artificial neural network

Reservoir fluid properties such as bubble point pressure, oil formation volume factor and viscosity are very important in reservoir and petroleum production engineering computations such as outflow–inflow well performance, material balance calculations, well test analysis, reserve estimates, and numerical reservoir simulations. Ideally, these properties should be obtained from actual measurements. Quite often, however, these measurements are either not available or very costly to obtain. In such cases, empirically derived correlations are used to predict the needed properties using the known properties such as temperature, specific gravity of oil and gas, and gas–oil ratio. Therefore, all computations depend on the accuracy of the correlations used for predicting the fluid properties. Almost all of these previous correlations were developed with linear or nonlinear multiple regression or graphical techniques. Artificial neural networks, once successfully trained, offer an alternative way to obtain reliable and more accurate results for the determination of crude oil PVT properties, because it can capture highly nonlinear behavior and relationship between the input and output data as compared to linear and nonlinear regression techniques. In this study, we present neural network-based models for the prediction of PVT properties of crude oils from Pakistan. The data on which the networks were trained and tested contain 166 data sets from 22 different crude oil samples and used in developing PVT models for Pakistan crude oils. The developed neural network models are able to predict the bubble point pressure, oil formation volume factor and viscosity as a function of the solution gas–oil ratio, gas specific gravity, oil specific gravity, and temperature. A detailed comparison between the results predicted by the neural network models and those predicted by other previously published correlations shows that the developed neural network models outperform most other existing correlations by giving significantly lower values of average absolute relative error for the bubble point, oil formation volume factor at bubble point, and gas-saturated oil viscosity.

Constraining tectonic compression processes by reservoir pressure evolution: Overpressure generation and evolution in the Kelasu Thrust Belt of Kuqa Foreland Basin, NW China

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N2k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day.

On the primary and secondary petroleum generating characteristics of the Bowland Shale, northern England

The Carboniferous Bowland Shale of northern England has drawn considerable attention because it has been estimated to have 1329 trillion cubic feet hydrocarbons in-place (gas and liquids) resource potential (Andrews 2013). Here we report on the oil and gas generation characteristics of three selected Bowland Shale whole-rock samples taken from cores and their respective kerogen concentrates. Compositional kinetics and phase properties of the primary and secondary fluids were calculated through the PhaseKinetics and GOR-Fit approaches and PVT modelling software. The three Bowland Shale samples contain immature, marine type II kerogen. Pyrolysate compositions imply primary generation of paraffinic–naphthenic–aromatic (PNA) oil with low contents of wax and sulphur. Bulk kinetic parameters have many similarities to those of productive American Palaeozoic marine shale plays. The secondary gas generation potential of Bowland Shale is greater than the primary gas potential although it requires a 10 kcal mol −1 higher activation energy to achieve peak production. Primary oil, primary gas and secondary gas reach their maximum generation at 137, 150 and 200°C respectively for a 3°C Ma −1 heating rate. Different driving forces of expulsion including the generation of hydrocarbon and overpressure caused by phase separation during sequential periods of subsidence and uplift could be inferred.

Gas Lift Nodal-Analysis Model Provides Economical Approach to Optimization

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171345, “Gas Lift Nodal-Analysis Model—Economical Optimization Approach,” by Mustafa Al Lawati, Occidental Petroleum, prepared for the 2014 SPE Artificial Lift Conference and Exhibition—North America, Houston, 6–8 October. The paper has not been peer reviewed. Field X consists of 17 scattered clusters of more than 100 oil wells producing from different reservoirs. Rapid expansion of the network has made the lifting network extremely busy and has resulted in many lowlifting- gas-rate ends. An easy solution is to increase lifting-gas use, but this is expensive. A more economical option is to restructure the gas lift surface pipelines, on the basis of proper engineering, by rerouting the surface network to reduce branching and enhance lifting-gas pressures and rates while maintaining the same level of lifting-gas use. Introduction The main gas lift 4-in. line connects Clusters A through C with the compressor. The main line is branched with 2-in. lines to every well in the cluster to deliver the required gas for lifting. As the number of wells increased dramatically, more low-rate and -pressure branches of the 2-in. lines were built. This was the main reason behind the loss of lifting efficiency. An increase of water cut in these clusters was another reason for loss of vertical-lift efficiency. Considering the operational challenges of the field, the easy yet expensive solution was to increase the volumes of lifting gas, knowing that 30 MMscf/D of gas already was used for lifting. A more-practical and -economical approach was, first, to build a numerical optimization model that could identify the low-pressure and -rate ends in the gas lift network on the basis of nodal analysis. The next step was to modify the gas lift network by rerouting the surface pipelines to help reduce any network branching and enhance lifting-gas pressures and rates accordingly across the network while maintaining the same volume of gas being used. Focusing on the three clusters— A, B, and C—pipeline rerouting and restructuring was implemented to debottleneck constraints at the surface network and to deliver lifting gas to high-productivity- index (PI) wells at optimum rates to optimize gas lift injection depth. Figs. 1 through 3 show the modifications made to these clusters. The main line is a 4-in. gas lift line, and the branched lines are all 2-in. lines. In Cluster A, a new 2-in. line was extended to the high-PI wells. The pipeline is represented in Fig. 1 by a dashed line. This allows for the delivery of higher lifting-gas rates, which helped optimize vertical-lift performance (VLP) of the wells by lifting from a deeper injection point while maintaining the same rate of lifting-gas use. The method of extending a new 2-in. line to high-PI wells was implemented again in Clusters B and C (Figs. 2 and 3, respectively). Methodology Pressure/Volume/Temperature (PVT) Characterization. The fluid PVT model is the first component of the integrated-nodal- analysis model. In this case, a surface fluid sample of Reservoir X from Cluster A was collected from the separator and tested in the laboratory. Later, the sample was modeled and characterized to evaluate the pressure-drop regime the fluid experiences along the production system, from the reservoir to the production separator. The characterization process includes the following: mass- balance calculation, compositional analysis, and entering the PVT laboratory data for matching to the equation of state. Reservoir Material-Balance Model. The reservoir material-balance model is the second component in the integrated model. To perform nodal analysis throughout the gas lift system, defining the production profile and static pressure of the tank (reservoir) from which the gas lift wells in Cluster A are producing is essential because defining an exact reservoir pressure is the starting point of any nodal analysis.

PVT modeling of reservoir fluids using PC-SAFT EoS and Soave-BWR EoS

Cubic equations of state, such as the Soave–Redlich–Kwong (SRK) and the Peng–Robinson (PR) EoS, are still the mostly used models in PVT modeling of reservoir fluids, and almost the exclusively used models in compositional reservoir simulations. Nevertheless, it is promising that recently developed non-cubic EoS models, such as the Perturbed Chain Statistical Associating Fluid Theory (PC-SAFT) EoS and the Soave modified Benedict–Webb–Rubin (Soave-BWR) EoS, may partly replace the roles of these classical cubic models in the upstream oil industry. Here, we attempt to make a comparative study of non-cubic models (PC-SAFT and Soave-BWR) and cubic models (SRK and PR) in several important aspects related to PVT modeling of reservoir fluids, including density description for typical pure components in reservoir fluids, description of binary VLE, prediction of multicomponent phase envelopes, and PVT calculation of reservoir fluids. Extensive data are used in the comparison and the four models are treated as equally as possible. We adopt the method of Pedersen et al. as the framework for heptanes plus characterization and the same correlations for estimating the critical properties for SRK, PR and Soave-BWR. For PC-SAFT, new correlations for estimating its model parameters in heptanes plus are developed. The results reveal that the non-cubic models are clearly advantageous in density calculation of pure components. For binary VLE and multicomponent phase envelopes, the results are similar for the four models. For PVT prediction, the non-cubic models show advantages in some high pressure high temperature (HPHT) fluids but no clear advantages in general, indicating the necessity for further improvement of the characterization procedure.

Identification of pitfalls in PVT gas condensate modeling using modified black-oil formulations

A black-oil (BO) PVT model is a fluid characterization formulation that represents multi-component reservoir hydrocarbons as a binary mixture (i.e., two pseudo-components: “surface gas” and “stock tank oil”). The BO PVT model is widely used in the petroleum industry because it is relatively simple compared to fully compositional modeling in which all or most components are independently accounted for. Since computational complexity increases nearly exponentially with number of components used in the characterization, there always remains a strong incentive to embracing the simplified black oil (binary) characterization as long as the fluid phase behavior allows it. When representing a complex system with this simplified model, a number of limitations arising from its simplicity may exist. In this study, these limitations are highlighted by performing phase behavior simulations for a gas condensate fluid. Rigorous calculations of standard (BO) PVT properties (Bo, Bg, Rs, and Rv) of a the gas condensate reservoir of choice are performed through a series of flash calculations at the prescribed reservoir fluid depletion path. The study demonstrates that the BO PVT model violates the species material balance principle as reservoir pressure depletes while conserving overall mass. This violation can lead to significant errors when coupling the BO PVT model with tank material balance-based techniques. The simulation test case indicates that these models will significantly and consistently underestimate oil formation volume factor (Bo) and solution gas oil ratio (Rs) due to the shortcomings of the BO PVT model.

Parameter estimation in multiple contact CO2 miscibility simulation with uncertain experimental core flooding data

CO2 flooding, which is an efficient method of enhanced oil recovery, is a very complicated process involving phase behavior. To understand the performance of CO2 flooding and provide accurate data for designing reservoir development, a comprehensive investigation of the phase behavior of CO2 miscible flooding and an accurate compositional reservoir simulation needs to be conducted. In PVT modeling, an effective and more physically reasonable equation of state model was achieved and the feasibility of CO2 miscible flooding was determined by multiple contact minimum miscibility pressure (MCMMP) calculation. Furthermore, compositional reservoir simulation studies for predicting CO2 miscible performance were designed and constructed with core flooding data. By matching with laboratory core flooding data, we can estimate parameters with uncertainty. The objective of this study was to find a work flow for parameter estimation in CO2 miscible flooding process that can be used to design and optimize field CO2 miscible floods.

Insights from fluid inclusions, thermal and PVT modeling for paleo-burial and thermal reconstruction of the Córdoba petroleum system (NE Mexico)

Carbonate reservoirs in the Córdoba petroleum system (NE Mexico) passed through a multiphase deformation history complicating the petroleum geology. The area evolved from passive margin and foreland setting to Laramide fold and thrust belt (FTB) that was subsequently buried below the Tertiary–Quaternary Veracruz Basin, which in turn underwent transpressional deformation. Reconstruction of paleo-burial (erosion) and paleo-thermicity through the different zones of the FTB and adjacent foreland is a challenging task since classical calibration tools fail to discriminate between several kinematic and thermal models. In this study results from detailed diagenetic and fluid inclusion (FI) analyses on carbonates from the western part of the Córdoba Platform helped constraining paleo-thermicity. Combined microthermometry, synchrotron FTIR analyses and PVT modeling of cogenetic hydrocarbon-aqueous FI allowed also calculation of absolute pressures. Thermal modeling exercises calibrated with organic maturity parameters, bottom-hole temperatures or temperatures from FI demonstrate that without controlling also paleo-erosion the model results may be misleading.

Synchrotron FTIR Hydrocarbon Fluid Inclusion Microanalysis Applied to Diagenetic History and Fluid Flow Reconstruction in Reservoir Appraisal

In sandstones, siliceous diagenetic overgrowths may commonly contain several generations of hydrocarbon fluid inclusions (FI's), generally of size no more than 10 µ. We successfully analyzed such inclusions in North sea sandstones from the Dunbar area, subthrusted reservoirs such as sub-Andean basins (Venezuelian and Colombian foothills) and carbonaceous series in areas of Pakistan, using synchrotron infrared microscopy. We addressed, for each case studied, molecular identification and mapping of the components, i.e. hydrocarbon content, and additional molecules such as CO2 , H2 O, in small volumes in their liquid and gas phase as well as the solid phases often associated as products or mechanically entrapped minerals. Semi-quantitative analysis leads to determination of the average composition of each inclusion, i.e equivalent aliphatic chain length (CH2 /CH3 ratios), CO2 and CH4 content. The quantitative method for hydrocarbon chain length measurements was tested first on some exceptionally large FI's (up to 500 µm) previously analyzed by gas chromatography after individual extraction. Homogeneity and /or heterogeneity of trapping as well association of oil with water or their separation is shown for each generation of FI corresponding to a specific organic fluid migration in sandstones from the Brent formation of Dunbar (North sea), and in siliceous reservoirs of subandin basins (Venezuelian and Colombian foothills). Microanalyses of solid phases closely associated within oil in such FI's indicate conditions of the dissolution-recrystallisation processes. Results are particularly promising in carbonaceous reservoirs of Northern Pakistan (Chorgali area, North Potwar basin) where first results pinpoint the effect of TSR mechanism in environments where evaporites were first deposited. PVT modeling of isochores using semi-quantitative SFTIR analyses leads to reconstruction of P-T conditions of diagenesis. Therefore by combining these results with data from organic matter (Genex modeling) and petrography, the onset of cementation was established in the Venezuelian and Colombian Foothills. The path of fluid migration along geological history was then reconstructed with Thrustpack 2D thermal modeling (IFP software), in Tunisian and Pakistani ore deposits and in the carbonaceous reservoir of Chorgali.

Pressure–temperature–time–composition ( P– T– t– X) constraints of multiple petroleum charges in the Hild field, Norwegian North Sea

The Brent reservoirs of the Hild field, situated at 3.8–4.3 km depth in the northern North Sea, show evidence of multiple episodes of diagenetic events, fracturing and petroleum charging. Data from fluid inclusions and drill stem test samples characterise the petroleum filling history of the Hild field. Two main types of petroleum inclusions occur. Type 1 inclusions, which occur in two of the fault compartments of the field, show a ‘heavier’ composition than the present reservoir fluids. From a comparison of fluid inclusion analyses and burial history, onset of reservoir filling is most likely represented by type 1 inclusions and took place at 125–130 °C in well 30/7-8R. This temperature corresponds to a burial depth of 3.5–3.7 km, which occurred 35–32 Ma ago. Type 2 inclusions occur in all wells and are compositionally similar to the reservoir fluids, suggesting recent trapping. Considerable differences in homogenisation temperature and phase behaviour of type 2 inclusions between the three wells of the Hild field indicate the compartmentalised nature of the reservoir. PVT modelling of fluid properties and trapping conditions was based on microthermometry, GC data for type 1 inclusions and present-day fluid compositional data for type 2 inclusions. The results show generally good agreement between estimated pressure for type 2 inclusions and present-day reservoir conditions, and an increase in overpressure between trapping of types 1 and 2 inclusions. We suggest that quartz cementation may continue after onset of reservoir filling, and may exert major control on the pressure evolution in deep reservoirs.

Geothermometry and geobarometry of overpressured environments in Qiongdongnan Basin, South China Sea*

AbstractWe demonstrate the use of PVT fluid inclusion modelling in the calculation of palaeofluid formation pressures, using samples from the YC21‐1‐1 and YC21‐1‐4 wells in the YC21‐1 structural closure, Qiongdongnan Basin, South China Sea. Homogenisation temperatures and gas/liquid ratios were measured in aqueous fluid inclusions, and associated light hydrocarbon/CO2‐bearing inclusions, and their compositions were determined using a crushing technique. The vtflinc software was used to construct P–T phase diagrams that enabled derivation of the minimum trapping pressure for each order of fluid inclusion. Through the projection of average homogenisation temperatures (155, 185.5 and 204.5°C) for three orders of fluid inclusion on the thermal‐burial history diagram of the Oligocene Yacheng and Lingshui formations, their trapping times were constrained at 4.3, 2.1 and 1.8 Ma, respectively. The formation pressure coefficient, the ratio of fluid pressure/hydrostatic pressure established by PVT modelling coupled with DST data, demonstrates that one and a half cycles of pressure increase–discharge developed in the Yacheng and Lingshui formations for about 4.3 Ma. In comparison, the residual formation pressure determined by 2D numerical modelling in the centre of LeDong depression shows two and a half pressure increase–discharge cycles for about 28 Ma. The two different methods suggest that a high fluid potential in the Oligocene reservoir of the YC21‐1 structure developed at two critical stages for regional oil and natural gas migration and accumulation (5.8 and 2.0 Ma, respectively). Natural gas exploration in this area is therefore not advisable.

Genesis and evolution of hydrocarbons entrapped in the fluorite deposit of Koh-i-Maran, (North Kirthar Range, Pakistan)

The exceptional development of coeval hydrocarbon and aqueous fluid inclusions (FI) in fluorite from the MVT-type ore deposit of Koh-i-Maran, Baluchistan (North Kirthar range, Pakistan), provides samples which are representative of the ore-forming fluid and which support the hypothesis of petroleum migration in the province. Primary brines at 125°C (10 wt% equ. NaCl) and secondary CH 4-rich brines at 135°C (7 wt% equ. NaCl), are recognised to be associated with oil migration in the fluid inclusions. They support the model of a per ascensum MVT (Mississippi Valley Type) stratabound hydrothermal deposit. A pressure–temperature path of 120–125°C to 165–200 bars is calculated from microthermometric data and PVT modelling of hydrocarbon FI using the modified Peng–Robinson Equation of State (IFP software) from primary cogenetic inclusions (oil and brines). The composition of gas and oil fractions is obtained by a combination of Synchrotron FTIR microanalysis and gas chromatography performed on individual fluid inclusions. The oil entrapped as a coeval primary fluid phase is a light aliphatic normal oil in the range C 8–C 35 with a high CO 2 content. The brown solid phase found systematically in the oil is probably asphaltene resulting from precipitation after trapping of the heavy fraction, which commonly occurs by decreasing pressure and temperature and\\or by CO 2 injection. Later CH 4-rich brine influx probably modified part of the oil in the primary fluid inclusions because degraded oil is observed within such inclusions. Biomarkers obtained by GC-MS analysis indicate a terpane distribution quite similar to the nearest oil seepage in the Gokurt area. This result and the high CO 2 content of organic fluid inclusions indicate a restricted/confined sedimentary environment for the source rock, which could correspond to the Eocene Carbonate formation with type-II organic matter. A possible additional input of gas from the Sambar formation is suggested as feasible. The link between the fluid inclusion data and the geodynamic evolution lead us to propose a circulation of basinal fluids driven mainly by the fault system during dewatering in the foredeep. In Pakistan, they are coeval to major compressional NW–SE Oligocene episode in the thrust belt. The origin of the fluorine may be found in the basin sediments as well as near the basement. The brines originated in salt structures recognized in eocambrian at the decollement level, the source rock was already mature.

PVTX history of the North Sea's Judy oilfield

Volumetric liquid:vapour ratios generated using a Confocal Laser Scanning Microscope are used along with PVT modelling software to estimate the composition, PT phase envelope and isochore of single petroleum inclusions in the North Sea's Judy field. The data are used to quantify pressure histories and to determine the compositional evolution of petroleum in the field. Important constraints are also placed on the permeability structure and history of the overlying chalk. Key conclusions are: (1) quartz cementation and the emplacement of low Gas–Oil Ratio oil occurred 1–3Ma ago in a significantly overpressured regime; (2) the present gas condensate was formed by the injection of gas-rich petroleum into a specific part of the field. Analysis of other North Sea fields suggests that many gas condensates form by the engulfment of oils by later gas.

Universal Neural-Network-Based Model for Estimating the PVT Properties of Crude Oil Systems

This study presents a universal neural-network-based model for the prediction of PVT properties of crude oil samples obtained from all over the world. The data, on which the network was trained, contains 5200 experimentally obtained PVT data sets of different crude oil and gas mixtures from all over the world. They were collected from major-producing oil fields in North and South America, the North Sea, Southeast Asia, the Middle East, and Africa. This represents the largest data set ever collected to be used in developing PVT models. An additional 234 PVT data sets were used to investigate the effectiveness of the neural-network models to predict outputs from inputs that were not used during the training process. The neural network model is able to predict the solution gas−oil ratio and the oil formation volume factor as a function of the bubble-point pressure, the gas relative density, the oil specific gravity, and the reservoir temperature. The neural-network models were developed using back-propagation with momentum for error minimization to obtain the most accurate PVT models. A detailed comparison between the results predicted by the neural-network models and those predicted by other correlations are presented for these crude oil samples. This study shows that artificial neural networks, once successfully trained, are excellent reliable predictive tools for estimating crude oil PVT properties better than available correlations. These neural-network PVT models can be easily incorporated into reservoir simulators and production optimization software.

The factors controlling the abundance and migration of heavy versus light oils, as constrained by data from the Gulf of Suez. Part I. The effect of expelled petroleum composition, PVT properties and petroleum system geometry

In the Gulf of Suez (GOS) petroleum systems the main factors which control the abundance and migration of heavy vs light oils are (a) the composition and PVT properties of the expelled fluids, (b) the geometry of the petroleum systems and (c) reservoir flow processes. Compositional and PVT modeling of the expelled petroleum fluids from the Brown Limestone and the Thebes Formation carbonate source rocks show the following. The fluids expelled below a transformation ratio of 0.5 are heavy oils (stock tank API gravity = 10–20°), have a low GOR, and contain 20–25% asphaltenes. These fluids are formed from source rocks which have mainly low to intermediate sulfur content and normal thermal stability. The further expelled fluids, up to a transformation ratio of around 0.97, are bubble point behaving fluids (oils) with stock tank API from >20–50°, and GOR ≈ 300–800 scf/bbl. and display a progressive decrease in asphaltene content. The latest ≈3% expelled fluids represent dew point behaving fluids (gas-condensates). The heavy, low GOR oils expelled below a transformation ratio of 0.5, have a very low saturation pressure and are not prone to asphaltene precipitation, unless they are mixed with higher GOR fluids. The PVT properties of these early expelled oils permit their efficient migration. This is consistent with an overabundance of low maturity asphaltenes in the GOS discovered heavy oils. The tendency for asphaltene precipitation is increased for the fluids expelled above a transformation ratio of 0.5, due to both a decrease in their asphaltene content, and an increase in GOR. Geometrically imposed mixing of fluids with large maturity-induced compositional differences, and reservoir flow processes have a significant effect on the PVT behavior of the migrating fluids, on asphaltene precipitation, and on the distribution of heavy vs light oils.

Correlation of unusual phase behaviour at elevated pressure

An unusual phase behaviour is in this context a phase behaviour which can not be correlated with a PVT model and the van der Waals approximation which is the most widely used mixture model in high pressure phase equilibrium thermodynamics. The van der Waals approximation is a successful model for correlation of phase equilibria in nonpolar fluid mixtures. All PVT models for reservoir fluids and in the petroleum industry are van der Waals approximations. In the chemical industry most phase equilibria are low pressure phase equilibria of systems containing polar compounds which can be correlated by means of an activity coefficient model. However, phase equilibria in systems containing mixed polar solvents and nonpolar solutes are difficult to correlate. In the last decade models have been developed which combine the complex composition dependence of activity coefficient models with equations of state. In the first part of the paper we review some rules of model developments set by the classical thermodynamics, although elementary, these rules are often overlooked, leading to inconsistent models. In the last part of the paper we review the state of the art of model developments and identify areas where further developments are warranted.