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Reservoir Fluids in Petroleum and Natural Gas Engineering
Abstract
The objective this research is to study the basic principles of reservoirs fluids, properties, phase behavior, and phase diagrams’ illustrations used to classify reservoirs types and inherent hydrocarbon systems.
Introduction
Hydrocarbons occur naturally in petroleum and natural gas reservoirs. However, their presence is contained in a mixture of organic compounds which display multiphase behavior depending on wide ranges of temperatures and pressures. The hydrocarbon fluids may exist in gaseous, liquid, and solid states or various mixtures of the same (Speight, 122).
In petroleum engineering, reservoir fluids fall into three main categories; liquid hydrocarbons, aqueous solutions containing dissolved salts, and hydrocarbon and non-hydrocarbon gases. The composition of all the particular cases above depends upon history, their sources, and the presence thermodynamic nature. The distribution of these fluids within a particular reservoir depends on the reservoir’s thermodynamic condition as well as the underlying rocks, and chemical and physical properties of the petroleum fluids themselves (Lyons, William & Gary, 50).
The differences in phase behavior, combined with the geophysical rock property that establishes the relative ease with which liquid and gas are retained or transmitted effects diverse types hydrocarbon fluid reservoirs exhibiting complex behaviors (Lyons, William & Gary, 51). Petroleum and natural gas engineers frequently have the task to examine the properties and behavior of petroleum reservoirs to evaluate the course of future production and development that would optimize the profit.
Methods
Reservoirs and fluids classification
The broad classification or reservoirs are gas and oil reservoirs. Further subdivisions depend on; initial temperature and pressure of reservoir, and of surface production, and hydrocarbon mixture composition. To obtain the phase conditions, the practical significance is of great consideration. The mathematical or experimental determinations of these situations are known as phase diagrams, and a single such diagram is referred to as pressure-temperature diagram. Below is an example of such as diagram showing a multicomponent system with particular general composition. Although various hydrocarbon systems would have a different illustration of phase diagrams, the overall configuration is analogous (Pedersen, Karen, Peter & Jawad, 56).

Figure 1: Pressure-temperature (p-t) diagram of a multicomponent system
Essentially, these multicomponent p-t systems help in classifying reservoirs, natural occurring hydrocarbon systems, and describing the phase characteristic of the reservoir fluid (Pedersen, Karen, Peter & Jawad, 57). To fully comprehend the value p-t diagrams, a petroleum engineer should establish and define the following major points: Cricondentherm (Tct) – the highest temperature beyond which liquid cannot form despite pressure (at point E). The pressure that corresponds to this temperature is cricondentherm pressure (Pct). Cricondenbar (Pcb) – the highest pressure beyond which gas cannot form whichever the temperature (point D). The temperature corresponding to this pressure is known as Cricondenbar temperature (Tcb). Critical point – a multicomponent mixture known as a state of temperature and pressure at which the entire intensive properties of both the liquid and gas phases are the same (point C). The temperature and pressure that corresponds to this point are critical pressure (Pc) and critical temperature (Tc) of the combination. Two-phase region (phase envelope) – the region bounded by the dew-point and bubble-point curves (line BCA). At this part, the liquid and gas coexist in equilibrium and is the hydrocarbon system’s phase envelope. Quality lines – the dashed or non-continuous lines that are in the phase diagram, and they describe the temperature and pressure conditions for the same liquid volumes. The line converges at the critical point C. Bubble-point curve – the point defined by the line BC separating the liquid-phase area from the two-phase part. Dew-point curve – the point defined by the line AC that separates the vapor-phase section from the region of two-phase.
Generally, petroleum engineers conveniently classify reservoirs on the concept of the location of the point that represents the initial pressure, pi and temperature, T of the reservoir regarding the p-t diagram of the reservoir fluid. The two broad categories of reservoirs are oil and gas reservoirs. Oil reservoirs exist if the temperature T is below the Tc of the reservoir fluid. On the other hand, gas reservoirs occur when the reservoir T is greater than the Tc of the hydrocarbon fluid (Ahmed, 86).
Results and Discussions
Oil Reservoir
Under this category, and depending on the initial reservoir pressure, Pi the subcategories include under-saturated, saturated and gas-cap oil reservoirs. First, the under-saturated oil reservoirs exist when pi of the reservoir fluid is higher than its bubble-point, pb. Second, the saturated oil is contained in reservoirs when the initial pressure, pi is equal to the reservoir fluid’s bubble-point pressure (at point 2). These reservoirs are saturated oil reservoirs. Last, gas-cap reservoir exists if the opening pressure, pi is lower than the bubble-point pressure (at point 3) of the reservoir fluid. It is also known as the two-phase reservoir, where the vapor or gas phase lies beneath an oil phase and the correct quality line produces the proportion ratio of the gas-cap to reservoir oil volume (Ahmed, 89).
Crude oil is a reservoir fluid that has a wide range of chemical and physical compositions and petroleum engineers group them into various categories related to particular oils. Crude oils have the following classifications: The normal black oil, low-shrinking, high-shrinking (crude oil), and near-critical crude oils. These classifications rely upon the properties unveiled by the crude oil, that is, composition, appearance, gas-oil ratio, and p-t phase diagrams. A characteristic crude oil composes thousands of various chemical compounds and separation into particular chemicals is impractical (Ahmed, 84). Separation is, however, done in fractions depending on the boiling point ranges of the compounds contained in each fraction. Main crude oil fractions are hydrocarbon gases, gasoline, kerosene, light gas oil, heavy gas oil, lubricants and waxes, and residuum. Each fraction of crude oil has its specific use. The residuum is vital in making tars, paving asphalt, petroleum jelly, wood preservatives, and coke. Lubricants and waxes help in paraffin wax, lubricating oil, and petroleum jelly. Heavy gas oil is useful in bunker fuel and lubricating oil. Light gas oil plays a role in diesel and furnace fuels while gasoline helps in solvents and motor fuels. Finally, hydrocarbon gases score in the fuel gas, solvents, and bottled fuel gases.
Chemical classification of crude oil depends on the structures displayed by the larger molecules in the composition. The technique uses combinations of words like asphaltic, aromatic, naphthenic, and paraffinic. For example, if oil crude predominantly contains paraffinic molecules, it yields essentially fine lubricating oils obtained from the gas-oil fraction as well as wax from residuum. However, in case the larger molecules are asphaltic and aromatic, the crude oil’s heavier fractions will be significant in paving asphalts, roofing compounds, and pitch among others applications (Ahmed, 89).
The liquid fluids in petroleum reservoirs have numerous divergent characteristics. For instance, some are tar-like, thick, heavy, and black while others are nearly clear or brown and have low viscosity and specific gravity. Nevertheless, these liquids (petroleum oils) have elemental analyses within some given limits, and they include oxygen, nitrogen, sulfur, hydrogen and carbon arranged from the lightest to the heaviest regarding weight percentages. The inconsistency is, however, remarkable. Therefore, a petroleum engineer must understand ranges of organic compounds, particularly in the reservoir fluid, their nomenclature, the degree of volatility, relation to one another, and the reactivity degree. Compounds behavior must clearly be understood when dealing with petroleum fluids properties (Lyons, William & Gary, 102).
Crude oil can either be classified by chemical structures or physical properties. The challenge exists in measuring the chemical property rather than the physical property. Physical properties are specific gravity, asphalt, sulfur, and kerosene and gasoline content, cloud point and pour point. In chemical properties, the six or fewer carbon atoms are primarily paraffins (Ahmed, 89). These classifications are based on thorough petroleum analysis carried out after removing most of the light molecules. Names such as aromatic-asphaltic, naphthenic-aromatic, naphthenic and paraffinic are examples of terms proposed after careful assessment of chemical structures of the crude oil mixtures. However, the separation is difficult because these large molecules may contain rings of condensed aromatic and naphthenic including paraffin chains on the sides. The analysis and classification are very tedious (Lyons, William & Gary, 101).
Phase diagrams for various oil reservoirs systems
Ordinary black oil

Figure 2: p-T phase diagram for ordinary black oil
The p-t phase diagram for ordinary black oil contains quality lines which are nearly equally spaced. Ordinary black oil yields an oil gravity of between 15 and 49 API, and a gas oil ratio (GOR) of between 200 and 700 scf/STB (Ahmed, 92). The oil in the stock tank is normally dark green or brown in color. Black oil composes of various components including heavy, large and non-volatile hydrocarbons. Following line EF indicating pressure reduction path, the liquid oil shrinkage curve can be prepared by plotting its volume as a function of pressure. The curve approximates a straight line except at extremely low pressures. The oil is undersaturated (easily dissolves more gas when present) when the pressure of the reservoir lies anywhere along EF. Oil is said to be saturated (cannot contain any more gas) if the pressure lies at E and free gas would exist in the reservoir.
Low-shrinkage oil

Figure 3: Liquid-shrinkage curve for black oil

Figure 4: Low-shrinkage oil phase diagram
The phase diagram has quality lines which are closely spaced close to the dew-point curve. This crude oil category has the following properties: first, the oil production volume factor is below 1.2 bbl/STB. Second, GOR is less than 200 scf/STB (Lyons, William & Gary, 103). Third, the oil gravity is below 35 degrees API. Fourth, the low-shrinkage oil has a black or a deep color. Lastly, the significant liquid recovery is at the separator condition at point G, at the 85% quality line (Ahmed, 88).
Volatile Crude Oil

Figure 5: Oil-shrinkage curve for low-shrinkage oil

Figure 6: p-T phase diagram for volatile crude oil
Volatile oil has fewer heavy hydrocarbon molecules and more ethane to hexane (intermediate components) than black oils. The above phase diagram for volatile crude oil has quality lines closer together near bubble-point and, at lower pressure, they quality lines are widely spaced. This crude oil type is characterized by high fluid shrinkage immediately below the point known as the bubble-point. Other properties include; its greenish or orange color, a fluid gravity of between 45 and 55 degrees API, GOR between 2,000 and 3,200 scf/STB, less than 2 bbl/STB volume factor for oil formation, and lower separator condition recovery at point G (Lyons, William & Gary, 105).

Figure 7: Oil-shrinkage curve for a volatile crude oil
Near-Critical Crude Oil

Figure 8: near-critical oil phase diagram

Figure 9: Shrinkage-curve for near-critical oil
In the case of the presence of near-critical crude oil, the reservoir temperature, T is near Tc of the fluid system. Since all quality lines meet at the critical point, C of the crude oil, isothermal pressure decline may shrink the fluid from 100% to 50% or less of the hydrocarbon pore volume at the point known as the bubble-point at a pressure of between 10 and 50 psi below the bubble-point. The near-critical crude oil has a high GOR with an increase of 3,000 scf/STB and the oil formation capacity factor of 2.0 bbl/STB or more. The fluid contains 12.5 to 20 molecular percentage of heptane-plus, ethane of 35% or more through hexane, and the remainder component is methane (Clark, 280).
Gas Reservoirs
In general, natural gas reservoirs exist when temperatures are above the critical temperature, Tc of the hydrocarbon systems. Reservoir gases, in this case, can exist in the following categories depending on the reservoirs’ prevailing conditions depicted in particular phase diagrams; dry gas, wet gas, near-critical gas condensate, and retrograde gas-condensate. The gaseous section of the reservoir fluids contains both hydrocarbon gases (that include butane and methane) and non-hydrocarbon gases which include mercaptan and hydrogen sulfide containing components (Lyons, William & Gary, 105).
Phase diagrams that represent Various Reservoir Fluids
Dry Gas Reservoir
Natural gases occur in the absence of liquid or condensate hydrocarbons, or they are gases that had condensable or liquid hydrocarbons removed. The temperature in the gas reservoir is above the cricondetherm, Tct. The temperature-pressure path line does not penetrate the phase diagram’s phase envelope, leading to the production of only dry gas on the surface, with no related liquid phase. The predominant fluid is primarily methane but contains some intermediate gases. No condensate or liquid surface liquid form in the reservoir and its surface and the hydrocarbon is solely a mixture of gases in such reservoirs. It is important to note that no liquid forms at the surface because the separator condition falls outside the phase envelope as opposed to in wet gas, that is, the pressure is often too high for liquids to exist. The gas oil ratio (GOR) is greater than 100,000 scf/STB.

Figure 10: dry gas phase diagram after Clark’s Elements of Petroleum Reservoirs
Wet or Rich Gas Reservoir
The reservoir fluid temperature, in this case, is just above the hydrocarbon mixture cricondentherm. Since the temperatures just exceed the Tct, of the hydrocarbon fluid system, the fluid within the reservoir will always be in the vapor phase region as the reservoir productions of fluids reduce in temperature and pressure (isothermically) along the temperature-pressure (t-p) path (A-B) (Ahmed, 88). The line just penetrates the phase envelope, leading to the release of gas with the associated liquid phase at the surface. This effect is due to a reduction in the kinetic energy of heavy hydrocarbon molecules with a drop in temperature and the subsequent conversion to liquid as a result of attractive forces. The wet gas reservoir has the following properties; gas oil ratio (GOR) is between 60,000 to 100,000 scf/STB, stock oil gravity higher than 60 degrees API, water-white liquid, and separator conditions than rest within the two-phase region. The natural gas contains substantially heavy hydrocarbons like butane, propane and other rich/wet gases. It is vital to not that the t-p path line does not get into the phase envelop, therefore, no liquid fluid exists inside the reservoir (Clark, 182).

Figure 11: Wet gas phase diagram after Clark’s Elements of Petroleum Reservoirs
Reservoir at near-critical gas-condensate
The hydrocarbon fluid mixture occurs when the reservoir temperature is at near the critical temperature, Tc petroleum engineers refer to the containing reservoir as the near-critical gas-condensate. The decline in the isothermal pressure and the corresponding liquid fluid dropout curve describe the volumetric nature of this category of the natural gas. All the lines converge at critical point C, hence a quick liquid build-up will promptly occur below the dew point as the pressure reduces to point 2. The fluid behavior indicated by the phase diagrams can be justified because the lines cross very rapidly with the isothermal decrease in pressure. At the point where the liquid begins to shrink or stops to build up, the reservoir changes from the retrograde to normal vaporization section (Clark, 183).

Figure 12: Near-critical gas-condensate reservoir phase diagram

Figure 13: Liquid shrinkage curve for near-critical gas-condensate reservoir
Retrograde gas-condensate Reservoir
The reservoir temperature T lying between Tc and Tct of the contained fluid is categorized as a retrograde gas-condensate system. This is a special type of hydrocarbon fluid accumulation because the unique thermodynamic characteristic of the reservoir fluid is the regulatory factor in its development and reservoir depletion. When, instead of the gas expansion or liquid vaporization as may be expected, the pressure is reduced on these mixtures, they are likely to vaporize in the place of condensing.

Figure 14: Liquid shrinkage in crude oil systems
A – low shrinkage oil, B – ordinary black oil, C – high shrinkage oil, and D – near-critical oil.
When pressure decreases in the reservoir, the fluid penetrates through the dew point, and the higher volumes of liquid condense in the reservoir. The gases flow preferentially to oil hence much of oil may be unrecoverable. Consequently, these reservoirs contain a re-inject dry gas and condensate gas to maintain the system’s pressure above the dew point to improve liquids recovery. In the phase diagram illustration shown below, retrograde gas completely exists in a gaseous state at point 1. The decrease in pressure makes the condensate to display a dew point, point 2. A further drop in pressure as the reservoir depletes, causes liquid condensation from gas to form a free liquid within the reservoir (Clark, 186).

Figure 15: A retrograde system phase diagram
Conclusion
Reservoir fluids can contain hydrocarbon liquids, gases, and aqueous solutions. Compositional analyses describe the composition of reservoir and reservoir fluids. These are characterized by the fluid energy content, separator condition optimization, and compositional simulation using the phase diagrams. Volume depletion experiments give quantitative information regarding volumetric characteristics of fluid condensate reservoirs when pressure drops (Totten, George & Victor J. De Negri, 33). The multiphase separator tests help in differential analyses of regular volume depletion to measure the reservoir fuels properties.

Works Cited
Ahmed, Tarek. Reservoir engineering handbook. Gulf Professional Publishing, 2006.
Clark, Norman Jack. Elements of petroleum reservoirs. Society of Petroleum Engineers of AIME, 1969.
Dandekar, Abhijit Y. Petroleum reservoir rock and fluid properties. CRC press, 2013.
Lyons, William C., and Gary J. Plisga. Standard handbook of petroleum and natural gas engineering. Gulf Professional Publishing, 2011.
Pedersen, Karen Schou, Peter L. Christensen, and Jawad Azeem Shaikh. Phase behavior of petroleum reservoir fluids. CRC Press, 2014.
Speight, James G. The chemistry and technology of petroleum. CRC press, 2014.
Terry, Ronald E., and J. Brandon Rogers. Applied petroleum reservoir engineering. Pearson Education, 2013.
Totten, George E., and Victor J. De Negri, eds. Handbook of hydraulic fluid technology. CRC Press, 2011.

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