Reservoirs fluid composition

Table III. Comparison of Reservoir Fluid Compositions - Low Pressure vs. High Pressure...

Three series of calculations (Experiments 1 to 3 below) were carried out to simulate the effects on the oil of the conceptual addition of gas, and subsequent modification of the mixture by evaporative fractionation. Gas addition was simulated using the recombination routine of WinProp, intended to determine reservoir fluid composition from separator gas and stock tank oil analyses. Here the tank oil is replaced by the full reservoir fluid analysis of the Boundary Lake oil. The separator gas is replaced by a hypothetical reservoir fluid representing the added gas. Post-injection oils were made up to a GOR of 178.11 m m at 13.79 MPa (1.0mcf/ bbl, 2000 psi) at the temperature of the experiment, compositions which would yield substantially higher GORs employing a conceptual separator operated at normal pressure and temperature. Experimental results in terms of Slope Factors are illustrated in Figure 11. 

Reservoir fluid compositions at each time step can be obtained for each reservoir in PetroMod. The reported fluid compositions were exported to PVTsim and the physical properties of the fluid calculated. The predicted physical properties were compared with those of the calibration data set and the individual compound kinetics of the multi-component kinetic model iteratively tuned until a good match was achieved (Fig. 4). Figure 6 and Table 4 show the tuned multi-component kinetic model for a marine Type II source rock developed by the method discussed previously. 

In many petroleum reservoirs around the world, reservoir fluid composition has been found to very with location and depth. Patel found the viscosity of Athabasca, Peace River, Wabasca and Cold Lake bitumens to vary with depth of the formation. Schulte explained the compositional variations within a hydrocarbon column by gravity segregation phenomenon. However, he found that the extent of variation to be higher with larger aromatic fractions in the hydrocarbon fluid. Hirschberg concluded that the heavy polar components play a key role in compositional and oil viscosity variation and in particular, identified asphaltene segregation to have a dominant effect. Hirschberg found that the... 

There are no definitions for categorising reservoir fluids, but the following table indicates typical GOR, API and gas and oil gravities for the five main types. The compositions show that the dry gases contain mostly paraffins, with the fraction of longer chain components increasing as the GOR and API gravity of the fluids decrease. 

The collection of representative reservoir fluid samples is important in order to establish the PVT properties - phase envelope, bubble point, Rg, B, and the physical properties - composition, density, viscosity. These values are used to determine the initial volumes of fluid in place in stock tank volumes, the flow properties of the fluid both in the reservoir and through the surface facilities, and to identify any components which may require special treatment, such as sulphur compounds. 

Deposition of adamantane from petroleum streams is associated with phase transitions resulting from changes in temperature, pressure, and/or composition of reservoir fluid. Generally, these phase transitions result in a solid phase from a gas or a liquid petroleum fluid. Deposition problems are particularly cumbersome when the fluid stream is dry (i.e., low LPG content in the stream). Phase segregation of solids takes place when the fluid is cooled and/or depressurized. In a wet reservoir fluid (i.e., high LPG content in the stream) the diamondoids partition into the LPG-rich phase and the gas phase. Deposition of diamondoids from a wet reservoir fluid is not as problematic as in the case of dry streams [74, 75]. 

Fig. 2.19. Reservoir temperature versus saturation indices (logQ/K) for calcite, anhydrite, K-feldspar and K-mica based on the estimated composition of reservoir fluid (Seki, 1991). Estimation based on gas results of Seki (1990), with saturation calculations carried out by PECS (Takeno, 1988). Gas concentrations were assumed to be 1 wt% of CO2 and 250 mg/kg for H2S for all wells (Seki, 1991).

In situ NMR measurements can be made in conjunction with down-hole fluid sampling [5, 6]. The NMR relaxation time and diffusivity can be measured under high-temperature, high-pressure reservoir conditions without loss of dissolved gases due to pressure depletion. In cases when the fluids may be contaminated by invasion of the filtrate from oil-based drilling fluids, the NMR analysis can determine when the fluid composition is approaching that of the formation [5, 6]. 

There has been extensive progress made in the past several years in the formulation of statistical thermodynamics of mixtures and transport phenomena modeling of multiphase flow in composite media. This knowledge may now be applied to the understanding and prediction of the phase and transport behavior of reservoir fluids and other... 

In part II of the present report the nature and molecular characteristics of asphaltene and wax deposits from petroleum crudes are discussed. The field experiences with asphaltene and wax deposition and their related problems are discussed in part III. In order to predict the phenomena of asphaltene deposition one has to consider the use of the molecular thermodynamics of fluid phase equilibria and the theory of colloidal suspensions. In part IV of this report predictive approaches of the behavior of reservoir fluids and asphaltene depositions are reviewed from a fundamental point of view. This includes correlation and prediction of the effects of temperature, pressure, composition and flow characteristics of the miscible gas and crude on (i) Onset of asphaltene deposition (ii) Mechanism of asphaltene flocculation. The in situ precipitation and flocculation of asphaltene is expected to be quite different from the controlled laboratory experiments. This is primarily due to the multiphase flow through the reservoir porous media, streaming potential effects in pipes and conduits, and the interactions of the precipitates and the other in situ material presnet. In part V of the present report the conclusions are stated and the requirements for the development of successful predictive models for the asphaltene deposition and flocculation are discussed. 

The evolution of the fluid composition reflects a lack of significant contact between the aqueous phase and the C02 while in the pore space of the reservoir. 

Geothermal reservoir rocks are typically fractured and therefore exhibit variable and anisotropic permeability. For that reason it is neither possible to predict with confidence how an injection well may perform with respect to its injectivity nor with respect to which way the injected fluid will flow once it is in the reservoir. Because of this complication, the success of injection varies between fields and it is anticipated that a special injection scheme must be developed for each field depending on its characteristics, mainly the three-dimensional distribution of permeability and the waste fluid composition. Injection may require drilling of special wells. Alternatively, wells drilled for the purpose of production may not have adequate yield but can be used successfully as injection wells. When this is the case, no special wells need to be drilled for injection purposes, which reduces road building and therefore scenery spoliation. 

Compositional changes in reservoir fluids and recovery factor... 

The injected fluids usually have a chemical composition that is different from that of the in situ reservoir fluids, particularly when steam has been separated from the liquid phase and only the separated water is re-injected. The steam phase will be enriched in non-condensable gases, whereas the separated water has a higher concentration of dissolved solids, but a lower gas content. Changes in the chemistry of the produced fluids are to be expected in all fields where re-injection of separated water has been applied. When the same water is recycled, successive steam loss will increase its salinity, which may in turn lead to scaling problems (see Amorsson, 2004). 

Laboratory determined compositions of volatile oils will have 12.5 to 30 mole percent heptanes plus. The dividing line between volatile oils and retrograde gases of 12.5 mole percent heptanes plus is fairly definite.2 When the heptanes plus concentration is greater than 12.5 mole percent, the reservoir fluid is almost always liquid and exhibits a bubble point. When the heptanes plus concentration is less than 12.5 mole percent, the reservoir fluid is almost always gas and exhibits a dew point. Any exceptions to this rule normally do not meet the rules of thumb with regard to stock-tank oil gravity and color. 

The reservoir pressure path on the phase diagram, Figure 5-3, indicates that at some low pressure the liquid begins to revaporize. This occurs in the laboratory however, it probably does not occur to much extent in the reservoir because during production the overall composition of the reservoir fluid changes. 

The reservoir fluid of Exercise 5-12 was sampled and the composition determined. 

Producing gas-oil ratio remained constant prior to sampling, so you may assume that the reservoir fluid is single phase. Calculate the composition of the reservoir fluid. What type of reservoir fluid is this ... 

Samples of gas and liquid are taken from a first stage separator operating at 500 psia and 75°F. The separator gas-oil ratio is constant at 2347 scf/SP bbl. The compositions of the samples are given in the table below. The density of the separator liquid at separator conditions, calculated with procedures given in Chapter 11, is 47.7 Ib/cu ft. Calculate the composition of the reservoir fluid. What type of reservoir fluid is this ... 

Compositions—Flash Vaporization—Differential Vaporization—Separator Tests—Oil Viscosity—Gas Viscosity Reservoir Fluid Properties from Reservoir Fluid Study... 

For resenroir engineering calculations various properties of the crude oil and its associated gas and water must be known. It will be shown that theoretically many of these properties could be calculated by the methods presented in previous chapters, provided the composition of the system is known and complete equilibrium constant data for all of the components are available. However, since this information is seldom at hand, values of the reservoir fluid characteristics are usually experimentally determined or approximated by methods that experience has shown to be sufliciently accurate for most engineering computations. 

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