Fluid, petroleum prediction

Undefined Fractions. The example applications illustrated above show the ability of the PR equation to make acceptable fluid property predictions for a wide variety of situations when the composition of the system is fully defined. At the present time, a suitable method has not been developed for characterizing the critical properties and acentric factor for an undefined fraction such as or its equivalent. Work is currently in progress on this problem. The Importance of being able to handle this kind of situation for industrial systems involving petroleum fractions can readily be appreciated. 

In Section 5.2.8 we shall look at pressure-depth relationships, and will see that the relationship is a linear function of the density of the fluid. Since water is the one fluid which is always associated with a petroleum reservoir, an understanding of what controls formation water density is required. Additionally, reservoir engineers need to know the fluid properties of the formation water to predict its expansion and movement, which can contribute significantly to the drive mechanism in a reservoir, especially if the volume of water surrounding the hydrocarbon accumulation is large. 

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. 

For practical purposes, saturated flow of a single fluid such as gasoline, kerosene, or another particular petroleum product can be predicted by the use of these equations. Standard units of linear measurement (feet, meters, etc.) and discharge are accommodated for by the corrections for viscosity and density. Field-testing procedures can be conducted using standard water well testing procedures. 

This revolution will spread to all chemical and petroleum processes that are large enough in scale to justify the investment in model building and experimental verification. Further progress needs better chemical kinetic data. The most deficient area remains in predicting the fluid mechanical and solid flow behaviors in reactors, where progress is sorely needed to round out the science of reaction engineering. 

The petroleum engineer should determine the type of fluid very early in the life of his reservoir. Fluid type is the deciding factor in many of the decisions which must be made regarding the reservoir. The method of fluid sampling, the types and sizes of surface equipment, the calcula-tional procedures for determining oil and gas in place, the techniques of predicting oil and gas reserves, the plan of depletion, and the selection of enhanced recovery method are all dependent on the type of reservoir fluid. 

A comparison of the predicted results from a calibrated computational fluid dynamics (CFD) model with experimentally measured hydrogen data was made to verify the calibrated CFD model. The experimental data showed the method predicted the spatial and temporal hydrogen distribution in the garage very well. A comparison was then made of the risks incurred from a leaking hydrogen-fueled vehicle and a leaking liquefied petroleum gas (LPG)-fueled vehicle. 

Further, molecular simulation and computational chemistry have evolved, and are evolving, into important tools for developing better characterization techniques where it is not possible to measure all data. Even so, it is precisely the molecular complexity of petroleum fluids that seems to be an inhibiting factor in the use of these methods for developing better characterization methods. However, identification of important functional groups in petroleum fluids applying molecular simulation and/or computational chemistry for use with group contribution methods to predict thermo-physical properties may be an area for further research. 

Makarov, V.K. and L.J. Morozov, 1980. Hydrodynamic barriers in petroliferous basins of North Africa. International Geology Review, Vol. 22, no. 11, pp. 1286-1290 Mann, D.M. and A.S. Mackenzie, 1990. Prediction of pore fluid pressures in sedimentary basins. Marine and Petroleum Geology, 7, pp. 55-65 Mann, U., 1989. Revealing hydrocarbon migration pathways. Geologische Rundschau 78/1, pp. 337-348... 

The chemistry of and physical mechanisms controlling the recovery of petroleum are better understood now than at any previous time yet, an extremely large amount of work remains before recoveries can be predicted with certainty. Part of this uncertainty arises from the undetermined variables of the heterogeneous reservoir matrix from which oil is produced and partly from simply not understanding the total interrelationship of the forces acting on the fluids in the reservoir. New chemical techniques and ideas for measurement undoubtedly will develop from the kinds of studies reported in this publication the result will be the achievement of a more efficient recovery of our petroleum resources. 

The concept of separate mobilities of the fluids can be used to make useful predictions of displacement behavior and has indeed been accepted without question by most of the petroleum-engineering profession. The combined mobility, Atotal, in this case is given in equation 3 as the sum of the mobilities of the two individual fluids where each fluid flows through the rock with distinct effective permeabilities, kel and ke2 The individual fluid viscosities, which are each measurable in bulk, are ju1 and p2-... 

Figure 9. Experimental and predicted rheograms for invert emulsion oil-based drilling fluids. Rheograms collected at 600 bar hydrostatic pressure and various temperatures (shown in degrees centigrade). (Reproduced with permission from reference 69. Copyright 1986 Society of Petroleum Engineers.)...

Although the equation of state can be and has been used to predict phase behavior for petroleum reservoir fluids for which no physical property data are available, it is recommended that some data, at least a saturation pressure, be measured in addition to a detailed component analysis of the fluid. This is particularly recommended when expensive compositional model studies are to be performed. 

Stainforth presents new models for reservoir filling and mixing. He presents data to support the idea that, in many cases, petroleum does not mix at all during reservoir filling. As new petroleum enters the trap, it fills from the crest of the structure, forcing previously emplaced petroleum downwards. This is a result of the general decrease in fluid density with maturity. This model predicts that the shapes of saturation pressure versus depth curves are related to trap geometry (depth versus volume curves) as well as source rock kitchen parameters. Field data are presented to support this model. 

However, current thermodynamic theories of compositional equilibrium under the combined influence of gravity and temperature fields do not adequately explain the large compositional gradients that are often encountered, except at conditions close to critical (Schulte 1980 Holt et al. 1983 Creek Schrader 1985 England et al. 1987 Nutakki et al. 1996). It is now quite common for the phenomenon of strong compositional grading to be associated with near-critical fluids, but the definition of near-critical fluids is rather broad and hazy Another problem with these theories is that they often do not predict the shape of these compositional depth trends at all well. In fact, Hoier Whitson (2001) doubt that most petroleum fields satisfy the fundamental assumptions in these models, especially that of zero mass flux (i.e. stationary state equilibrium). 

Montel, F. Gouel, P. L. 1985. Prediction of compositional grading in a reservoir fluid column. Society of Petroleum Engineers, Paper No. 14410. 

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