A multicomponent mixture exhibits an envelope for liquid/vapor phase change in the pressure/temperature diagram, which contains a bubble-point line and a dew-point line, compared with only a phase change line for a pure component. The various reservoir types of oil and gas systems based on the phase behavior of hydrocarbons in the reservoir, inwhich the following five types of reservoirs are distinguished:
- Black oils;
- Volatile oils;
- Condensate (retrograde gases);
- Wet gases;
- Dry gases.
The amount of heavier molecules in the hydrocarbon mixtures varies from large to small in the black oils to the dry gases, respectively.
Black oil is liquid oil and consists of a wide variety of chemical species including large, heavy, and nonvolatile molecules. Typical black oil reservoirs have temperatures below the critical temperature of a hydrocarbon mixture. Point C1 in the same figure shows saturated back oil, which means that the oil contains as much dissolved gas as it can take and that a reduction of system pressure will release gas to form the gas phase. In transport pipelines, black oils are transported in the liquid phase throughout the transport process, whereas in production flowlines, produced hydrocarbon mixtures are usually in thermodynamical equilibrium with gas.
Volatile oils contain fewer heavy molecules than black oil, but more ethane through hexane. Reservoir conditions are very close to the critical temperature and pressure. A small reduction in pressure can cause the release of a large amount of gas.
CondensateRetrograde gas is the name of a fluid that is gas at reservoir pressure and temperature. However, as pressure and temperature decrease, large quantities of liquids are formed due to retrograde condensation. Retrograde gases are also called retrograde gas condensates, gas condensates, or condensates.
For a pure substance a decrease in pressure causes a change of phase from liquid to gas at the vapor–pressure line; likewise, in the case of a multicomponent system, a decrease in pressure causes a change of phase from liquid to gas at temperatures below the critical temperature.
A wet gas exists in a pure gas phase in the reservoir, but becomes a liquid/gas two-phase mixture in a flowline from the well tube to the separator at the topside platform. During the pressure drop in the flowline, liquid condensate appears in the wet gas.
Dry gas is primarily methane. The hydrocarbon mixture is solely gas under all conditions of pressure and temperature encountered during the production phases from reservoir conditions involving transport and process conditions. In particular, no hydrocarbon-based liquids are formed from the gas although liquid water can condense. Dry gas reservoirs have temperatures above the cricondentherm.
Accurate prediction of physical and thermodynamic properties is a prerequisite to successful pipeline design. Pressure loss, liquid hold up, heat loss, hydrate formation, and wax deposition all require knowledge of the fluid states.
In flow assurance analyses, the following two approaches have been used to simulate hydrocarbon fluids:
- “Black-oil” model: Defines the oil as a liquid phase that contains dissolved gas, such as hydrocarbons produced from the oil reservoir. The “black oil” accounts for the gas that dissolves (condenses) from oil solution with a parameter of Rs that can be measured from the laboratory. This model predicts fluid properties from the specific gravity of the gas, the oil
gravity, and the volume of gas produced per volume of liquid. Empirical correlations evaluate the phase split and physical property correlations determine the properties of the separate phases.
- Composition model: For a given mole fraction of a fluid mixture of volatile oils and condensate fluids, a vapor/liquid equilibrium calculation determines the amount of the feed that exists in the vapor and liquid phases and the composition of each phase. It is possible to determine the quality or mass fraction of gas in the mixtures. Once the composition of
each phase is known, it is also possible to calculate the interfacial tension, densities, enthalpies, and viscosities of each phase.
The accuracy of the compositional model is dependent on the accuracy of the compositional data. If good compositional data are available, selection of an appropriate EOS is likely to yield more accurate phase behavior data than the corresponding black-oil model. This is particularly so if the hydrocarbon liquid is a light condensate. In this situation complex phase effects such as retrograde condensation are unlikely to be adequately handled by the black-oil methods. Of prime importance to hydraulic studies is the viscosity of the fluid phases. Both black-oil and compositional techniques can be inaccurate.
Depending on the correlation used, very different calculated pressure losses could result. With the uncertainty associated with viscosity prediction, it is prudent to utilize laboratory-measured values. The gas/oil ratio (GOR) can be defined as the ratio of the measured volumetric flow rates of the gas and oil phases at meter conditions (multiphase meter) or the volume ratio of gas and oil at the standard condition (1 atm, 60 F) in units of scf/STB. When water is also present, the water cut is generally defined as the volume ratio of the water and total liquid at standard conditions. If the water contains salts, the salt concentrations may be contained in the water phase at the standard condition.
 R.C. Reid, J.M. Prausnitz, T.K. Sherwood, The Properties of Gases and Liquids, third ed., McGraw-Hill, New York, 1977.
 K.S. Pedersen, A. Fredenslund, P. Thomassen, Properties of Oils and Natural Gases, Gulf Publishing Company (1989).
 T.W. Leland, Phase Equilibria, Fluid, Properties in the Chemical Industry, DECHEMA, Frankfurt/Main, 1980. 283–333.
 G. Soave, Equilibrium Constants from a Modified Redilich-Kwong Equation of State, Chem. Eng. Sci vol. 27 (1972) 1197–1203.
 D.Y. Peng, D.B. Robinson, A New Two-Constant Equation of State, Ind. Eng. Chem. Fundam. vol. 15 (1976) 59–64.
 G.A. Gregory, Viscosity of Heavy Oil/Condensate Blends, Technical Note, No. 6, Neotechnology Consultants Ltd, Calgary, Canada, 1985.
 G.A. Gregory, Pipeline Calculations for Foaming Crude Oils and Crude Oil-Water Emulsions, Technical Note No. 11, Neotechnology Consultants Ltd, Calgary, Canada, 1990.
 W. Woelflin, The Viscosity of Crude Oil Emulsions, in Drill and Production Practice,, American Petroleum Institute vol. 148 (1942) p247.
 E. Guth, R. Simha, Untersuchungen u¨ber die Viskosita¨t von Suspensionen und Lo¨sungen. 3. U¨ ber die Viskosita¨t von Kugelsuspensionen, Kolloid-Zeitschrift vol. 74 (1936) 266–275.
 H.V. Smith, K.E. Arnold, Crude Oil Emulsions, in Petroleum Engineering Handbook, in: H.B. Bradley (Ed.), third ed., Society of Petroleum Engineers, Richardson, Texas, 1987.
 C.H. Whitson, M.R. Brule, Phase Behavior, Monograph 20, Henry, L. Doherty Series, Society of Petroleum Engineers, Richardson, Texas, (2000).
 L.N. Mohinder (Ed.), Piping Handbook, seventh, ed., McGraw-Hill, New York, 1999.
 L.F. Moody, Friction Factors for Pipe Flow, Trans, ASME vol. 66 (1944) 671–678.
 B.E. Larock, R.W. Jeppson, G.Z.Watters, Hydraulics of Pipeline Systems, CRC Press, Boca Raton, Florida, 1999.
 Crane Company, Flow of Fluids through Valves, Fittings and Pipe, Technical Paper No. 410, 25th printing, (1991).
 J.P. Brill, H. Mukherjee, Multiphase Flow in Wells, Monograph vol. 17(1999), L. Henry, Doherty Series, Society of Petroleum Engineers, Richardson, Texas.
 H.D. Beggs, J.P. Brill, A Study of Two Phase Flow in Inclined Pipes,, Journal of Petroleum Technology vol. 25 (No. 5) (1973) 607–617.
 Y.M. Taitel, D. Barnea, A.E. Dukler, Modeling Flow Pattern Transitions for Steady Upward Gas-Liquid Flow in Vertical Tubes, AIChE Journal vol. 26 (1980) 245.
 PIPESIM Course, Information on Flow Correlations used within PIPESIM, (1997). 398 Y. Bai and Q. Bai
 H. Duns, N.C.J. Ros, Vertical Flow of Gas and Liquid Mixtures in Wells, Proc. 6th World Petroleum Congress, Section II, Paper 22-106, Frankfurt, 1963.
 J. Qrkifizewski, Predicting Two-Phase Pressure Drops in Vertical Pipes, Journal of Petroleum Technology (1967) 829–838.
 A.R. Hagedom, K.E. Brown, Experimental Study of Pressure Gradients Occurring During Continuous Two-Phase Flow in Small-Diameter Vertical Conduits, Journal of Petroleum Technology (1965) 475–484.
 H. Mukherjce, J.P. Brill, Liquid Holdup Correlations for Inclined Two-Phase Flow, Journal of Petroleum Technology (1983) 1003–1008.
 K.L. Aziz, G.W. Govier, M. Fogarasi, Pressure Drop in Wells Producing Oil and Gas, Journal of Canadian Petroleum Technology vol. 11 (1972) 38–48.
 K.H. Beniksen, D. Malnes, R. Moe, S. Nuland, The Dynamic Two-Fluid Model OLGA: Theory and Application, SPE Production Engineering 6 (1991) 171–180. SPE 19451.
 A. Ansari, N.D. Sylvester, O. Shoham, J.P. Brill, A Comprehensive Mechanistic Model for Upward Two-Phase Flow in Wellbores, SPE 20630, SPE Annual Technical Conference, 1990.
 A.C. Baker, K. Nielsen, A. Gabb, Pressure Loss, Liquid-holdup Calculations Developed, Oil & Gas Journal vol. 86 (No 11) (1988) 55–59.
 O. Flanigan, Effect of Uphill Flow on Pressure Drop in Design of Two-Phase Gathering Systems, Oil & Gas Journal vol. 56 (1958) 132–141.
 E.A. Dukler, et al., Gas-Liquid Flow in Pipelines, I. Research Results, AGA-API Project NX-28 (1969).
 R.V.A. Oliemana, Two-Phase Flow in Gas-Transmission Pipeline, ASME paper 76- Pet-25, presented at Petroleum Division ASME Meeting, Mexico City, (1976).
 W.G. Gray, Vertical Flow Correlation Gas Wells API Manual 14BM (1978).
 J.J. Xiao, O. Shoham, J.P. Brill, A Comprehensive Mechanistic Model for Two-Phase Flow in Pipelines, SPE, (1990). SPE 20631.
 S.F. Fayed, L. Otten, Comparing Measured with Calculated Multiphase Flow Pressure Drop, Oil & Gas Journal vol. 6 (1983) 136–144.
 Feesa Ltd, Hydrodynamic Slug Size in Multiphase Flowlines, retrieved from http:// www. feesa.net/flowassurance.(2003).
 Scandpower, OLGA 2000, OLGA School, Level I, II.
 Deepstar, Flow Assurance Design Guideline, Deepstar IV Project, DSIV CTR 4203b–1, (2001).
 J.C. Wu, Benefits of Dynamic Simulation of Piping and Pipelines, Paragon Technotes (2001).
 G.A. Gregory, Erosional Velocity Limitations for Oil and Gas Wells, Technical Note No. 5, Neotechnology Consultants Ltd, Calgary, Canada, 1991.
 American Petroleum Institute, Recommended Practice for Design and Installation of Offshore Platform Piping System, fifth edition,, API RP 14E, 1991.
 M.M. Salama, E.S. Venkatesh, Evaluation of API RP 14E Erosional Velocity Limitations for Offshore Gas Wells, OTC 4485 (1983). Hydraulics 399