Gas Reservoirs PDF

MODULE 4: TYPES OF PETROLEUM RESERVOIRS Petroleum Reservoirs: A petroleum reservoir is a subsurface pool of hydrocarbons contained in underground porous and permeable rocks and fractures as a single hydraulically connected system. Petroleum reservoirs are broadly categorized into two as oil and gas...

MODULE 4: TYPES OF PETROLEUM RESERVOIRS Petroleum Reservoirs: A petroleum reservoir is a subsurface pool of hydrocarbons contained in underground porous and permeable rocks and fractures as a single hydraulically connected system. Petroleum reservoirs are broadly categorized into two as oil and gas reservoirs. Many hydrocarbon reservoirs are hydraulically connected to various volumes of water-bearing rocks, called aquifers. In general, deposits rich in oil (or liquid petroleum) are called oil fields, and deposits rich in natural gas (or gaseous petroleum) are called natural gas fields. Oil reservoirs occur at shallower depths of 1,000 m to 6,000 m (1𝑚 ≅ 3.28084 𝑓𝑡) (at temperatures of 140𝑜 𝐹 to 302𝑜 𝐹) when compared to gas reservoirs which are found buried deeper and at higher temperatures. Reservoir fluids from different sources have different compositions which determine their characteristics. For natural gas reservoirs, the amount of ethane plus (𝐶2 + ) fractions (also called natural gas liquids (or NGL)), contained in the gas mixture, determines the amount of liquid that would condense from the gas (called condensates) when it is produced to the surface owing to the lower surface temperature and pressure. Natural gas with appreciable amount of NGL capable of producing condensates at surface conditions is termed “wet gas”. The deeper the natural gas reservoir, the "drier" the gas (that is, the smaller the proportion of high molecular weight hydrocarbon fractions that would be present in the gas mixture, thus the lesser the amount of surface condensates that may be recovered at standard conditions.. 4.1 Phase Diagram of Hydrocarbon Reservoir Fluid (Multicomponent) System: A Phase diagram, (sometimes called phase envelope) is a graphical representation of the physical states of a substance under different conditions of temperature and pressure. Phase diagrams are useful in studying the behavior of reservoir fluids in relation to their temperature and pressure at initial conditions and at other stages of production. The basic concept of the phase diagram is the same for different types of reservoir fluids, though there are slight variations. This makes it possible to use a single phase diagram to study various reservoir fluid types. A typical phase diagram has pressure, (P) on the y-axis and temperature, (T) (or specific volume, v) on the x-axis. A typical P-T phase diagram, is illustrated by figure 4.1 below. Each point within the diagram corresponds to a particular combination of pressure and temperature, and provides information on the state of matter as well as the phase or phases at the given conditions.  P Single phase KEY 𝑷𝒎𝒂𝒙 C Vapour Single phase Letter Meaning Liquid B Bubble point line Liquid + Vapour P Fluid Pressure T Fluid tempeature B C Critical point D Dew point line 𝑃𝑚𝑎𝑥 Cricondenbar 𝑇𝑚𝑎𝑥 Cricondentherm % Liquid D 𝑻𝒎𝒂𝒙 T Figure 4.1 P-T Phase Diagram (or phase envelope) of a multi component system On a multi component systems’ phase diagram, such as is depicted by figure 4.1, crude oil reservoirs occur to the left of the critical point (above or below the bubble point line) while natural gas reservoirs occur to the right of the critical point (above or below the dew point line). The saturation or otherwise of oil or gas reservoirs may be determined by the position of the reservoir temperature and pressure on the phase envelope (or phase diagram) as follows: (i) If a reservoir’s temperature and pressure conditions plot above the bubble point line, that is, reservoir temperature, 𝑇𝑟 is less than the critical temperature, 𝑇𝑐 and reservoir pressure, 𝑃𝑟 is above bubble point pressure, 𝑃𝑏 i.e. [(𝑇𝑟 < 𝑇𝑐 ) 𝑎𝑛𝑑 (𝑃𝑟 > 𝑃𝑏 )], the reservoir is an under- saturated crude oil reservoir the reservoir fluid is single phase liquid; (ii) If reservoir’s temperature and pressure conditions plot below the bubble point line, it means that the reservoir temperature, 𝑇𝑟 is less than the critical temperature, 𝑇𝑐 and reservoir pressure, 𝑃𝑟 is below bubble point pressure, 𝑃𝑏 i.e. [(𝑇𝑟 < 𝑇𝑐 ) 𝑎𝑛𝑑 (𝑃𝑟 < 𝑃𝑏 )], the reservoir is a saturated crude oil reservoir, and the reservoir fluid is two phase, liquid and vapour in equilibrium; (iii) If reservoir temperature and pressure conditions plot above the dew point line, the reservoir temperature, 𝑇𝑟 is greater than the critical temperature, 𝑇𝑐 and reservoir pressure, 𝑃𝑟 is above dew point pressure, P𝑃𝑑 i.e. [(𝑇𝑟 > 𝑇𝑐 ) 𝑎𝑛𝑑 (𝑃𝑟 > 𝑃𝑑 )], the reservoir is an under-saturated natural gas reservoir, and the reservoir fluid is single phase, gas. (iv) If reservoir temperature and pressure conditions plot below the dew point line, that is, the reservoir temperature, 𝑇𝑟 is greater than the critical temperature, 𝑇𝑐 and reservoir pressure, 𝑃𝑟 is below the dew point pressure, 𝑃𝑑 i.e. [(𝑇𝑟 > 𝑇𝑐 ) 𝑎𝑛𝑑 (𝑃𝑟 < 𝑃𝑑 )], the reservoir is a saturated natural gas reservoir, and the reservoir fluid is two phase, oil and gas in equilibrium. 4.2 Definitions of Basic Terms Bubble Point: Bubble Point is the temperature at a certain pressure at which the first bubble of gas evolves from a liquid phase to form a separate gas phase in addition to the liquid phase. Bubble Point Pressure: This is the pressure, at reservoir temperature at which the first bubble of gas would escape from the liquid phase to form a gas phase, called gas cap, above the oil zone. Crude oil reservoirs for which the reservoir pressure is above the fluid bubble point pressure are said to be under-saturated. This means that the fluid does not contain as much gas bubbles within it as it has capacity to dissolve, or that, if more gas bubbles were to be made available, the gas would easily dissolve into the oil to form a solution, at the prevailing reservoir T and P condition. Thus, a slight reduction in pressure, due to production, does not lead to evolution of gas from the liquid oil phase and the fluid remains in one (liquid) phase as pressure is allowed to decline, provided pressure remains above the bubble point pressure If pressure were allowed to fall to the bubble point pressure, for example, due to production without pressure support, the first bubble of gas would evolve from the liquid phase to form a gas phase above the liquid phase. As pressure falls further below the bubble point pressure, more gas evolves and because gas has lower density than oil, it accumulates above the oil phase to form what is known as “gas cap”. Reservoir crude oil systems at and below the bubble point pressure of the fluid is said to be “saturated”, because, it contains the most gas as it can keep dissolved into the oil at the given temperature and pressure of reference. As a result, any slight decrease in pressure causes gas to evolve from the oil phase. Saturated oil reservoirs are sometimes referred to as “gas cap reservoirs”. They contain two phases, liquid and vapour coexisting at equilibrium with the gas phase (gas cap), above the oil phase zone in the reservoir. Bubble Point Line: Bubble Point line is the locus of points joining various bubble points for a given system; that is, for different temperatures and corresponding bubble point pressure conditions. The bubble point line is labelled as “B” in figure 4.1 Condensate: Liquid that condensed from a gas phase as a result of changing temperature and pressure conditions. Cricondenbar: The maximum pressure at which two phase (oil and gas) can coexist is the cricondenbar. Above this pressure, the two phase region cannot exist whatever the temperature. Cricondentherm: This is the maximum temperature of the two phase (liquid and gas) region or the temperature above which the two phases cannot exist together whatever the pressure. Critical point: This is a point on a phase diagram at which both the liquid and gas phases of a substance have the same density, and are therefore indistinguishable. For a multi component system like natural gas, it is the meeting point of the bubble point and dew point lines. Dew Point: This is the temperature and pressure at which the first drop of liquid condenses from a vapour phase to form an independent liquid phase. The gaseous system before the dewpoint is reached is termed under-saturated but at the dew point (and below), the system is termed saturated. Dew Point Line: The locus of points joining dew points is called the dew point line. The dew point line is labelled “D” in figure 4.1. Thus, the saturation point of a gaseous system is called dew point whereas the saturation point of a liquid system is called bubble point. For a single component system, that is a system consisting of only one chemical compound, the bubble point and dew point coincide and both are equal to its boiling point, which is the temperature at a given pressure at which the liquid starts to boil. The locus of points joining various boiling points at varying temperatures and corresponding pressures) is called the vapour pressure curve. Figure 4.2 illustrates this. The Phase Rule The phase rule proposed by the American chemist J. Willard Gibbs in 1876 has the form: 𝐹 =𝐶+2−𝑃 (4.1) In Eq. (4.1), 𝐹 is the number of degrees of freedom. It describes the minimum number of variables that must be fixed in order to define a particular condition of the system, also called the variance. 𝑃 refers to the number of phases present in the system and 𝐶 is the number of independent chemical components required to describe the composition of all the phases within the system.  Melting Pont Curve Or Fusion Pont Curve Or Freezing Pont Curve Boiling Point Curve Or Vapourization Curve Sublimation Curve Or Deposition Curve Figure 4.2. Phase diagram of a single component system (Source: https://chem.libretexts.org/Bookshelves/Physical_and_Theoretical_Chemistry_Textbook_Maps/Supplemental_Mod ules_(Physical_and_Theoretical_Chemistry)/Physical_Properties_of_Matter/States_of_Matter/Phase_Transitions/Ph ase_Diagrams) It is important to note that as shown in Figure 4.2, the critical point for a single component system constitutes the upper limit of the vapour-pressure (or boiling point) curve. Figure 4.2 shows the regions in which the system may exist in single phase solid, liquid or vapour states. The lines represent the combinations of pressures and temperatures at which two phases can exist in equilibrium. Solid and liquid on the melting point (or sublimation curve), liquid and vapour on the boiling point (or vapour pressure) curve, and solid and vapour on the sublimation (or deposition) curve. Normally the solid/liquid phase line slopes positively to the right (as shown in the diagram by the green solid line labeled melting point curve). However for other substances, notably water, the line slopes to the left (as shown by the dotted green line in the diagram). This indicates that the liquid phase is denser than the solid phase. Triple Point: The lower limit of the boiling point curve is called the Triple point. This is the temperature and pressure conditions at which the three phases of matter, solid, liquid and gas, are in equilibrium with themselves in such a way that they are identical and indistinguishable from one another. With most substances, the triple point lie below standard temperature and pressure whereas the pressure at the critical point exceeds standard pressure. Figure 4.3 States of matter (Source: https://www.britannica.com/science/phase-state-of-matter) 4.3 Types of Crude Oil Reservoirs There are basically two types of crude oil reservoirs based on the position of the reservoir temperature and pressure when plotted on a phase diagram. These are: (i) Black oil (Low shrinkage crude oil) reservoirs and (ii) Volatile oil (High shrinkage crude oil) reservoirs. 4.3.1 Black Oil (Low Shrinkage Crude Oil) Reservoirs Black oil reservoirs, sometimes referred to as low shrinkage oil reservoirs, occur to the left of the critical point on a phase diagram at considerable distance from the critical point. For an under- saturated black oil reservoir, the initial reservoir pressure and temperature plots above the bubble point line to the left of the critical point as depicted as point 1 in figure 4.3 below. Thus, the reservoir temperature is considerably lower than the critical temperature, 𝑇𝑐 , or 𝑇𝑟 ≪ 𝑇𝑐. At initial conditions, the reservoir fluid is single phase liquid oil with dissolved gas in solution. During production at reservoir conditions, pressure falls at constant reservoir temperature (isothermally) along the path1-2 as shown in figure 4.3. When pressure has fallen to point 2, the reservoir fluid becomes saturated and lets off the first bubble (infinitesimal amount) of gas that would have to remain in equilibrium with an enormous amount of liquid (bubble point). Due to the lighter density of the gas phase in comparison to the oil, the gas formed occupies the upper positions of the reservoir rock to form a gas cap. On further production, pressure continues to fall isothermally in the reservoir to below that at point 2, such as at point 3. This causes an increase in the gas phase volume as more gas bubbles evolve from the oil solution. If production from the reservoir continues, the fluid being produced will include crude oil (with the gas dissolved in it), some free natural gas from the gas cap gas, and, possibly, some water as connate water. The weight of the fluids is often a challenge to bring to surface especially at low reservoir pressures. At some point during the depletion process, the natural pressure in the reservoir becomes so low that it can no longer overcome the weight of the fluids in the wells and lift these fluids to the surface using the natural reservoir energy. This would necessitate the need for installation of some form of artificial lift (e.g., pumps) to support the natural reservoir pressure lift the reservoir fluids to the surface. This is usually an expensive venture and adds to the financial burden of the operator. Production would have to stop when it is no longer profitable to continue production from the reservoir. The pressure at which production from the reservoir is stopped because the economic limit has been reached (the limit at which the reservoir can be profitably produced) is called the “abandonment pressure,” 𝑷𝒂. Position 3 on the phase diagram may be considered to be the abandonment pressure for the reservoir depicted by the illustration of Figure 4.4. For isothermal processes, the pressure-temperature path of the fluids inside the reservoir is a vertical line at a fixed temperature, which happens to be the reservoir temperature, 𝑇𝑟. This is represented in Figure 4.4 as the solid straight line going from Point 1 to point 2, (the bubble point of the reservoir fluid) to Point 3. The fluid being produced to the surface follows the slanted path from point 1 to the separator, labeled “S”, observing reducing temperature and pressure as it is travels from the reservoir, which is at high temperature and pressure to the surface separators, at lower temperature and pressure conditions.  Critical Point 1 2 3 % Liquid S Dew Point line Temperature Figure 4.4 Phase Diagram of a Black Oil Reservoir Black oil reservoirs are called “low shrinkage oils” because, being far from the gas region which is anywhere from the critical temperature and above, the amount of gas originally dissolved in the reservoir crude is less than could be found in crude oil reservoirs which occur at temperatures closer to the critical temperature. As a result, on being produced to the separators, the amount of gas separated from the produced oil volume is less than significant, so that the reduction in volume of the oil as a result is minimal. 4.3.2 Volatile Oil (High Shrinkage Crude Oil) Reservoirs Volatile (or high shrinkage) oil reservoirs are characterized by reservoir temperatures that are less than, but close to the critical temperature, 𝑇𝑟 < 𝑇𝑐. This reservoir fluid type contains significant amounts of dissolved gas in solution in the oil (relative to low shrinkage crude oils). If system pressure falls to pressures below its bubble point pressure (such as during production), the fluid gives off much of the gas that is responsible for a greater fraction of its original volume and the remaining fluid (oil without the dissolved gas) is small compared to the volume before the gas release. This can happen for the fluid in the reservoir as well as for the fluid produced to the surface. The resulting oil is said to have shrunk considerably from its initial volume. Therefore, this crude oil type is often referred to as “High Shrinkage Crude Oils”. Allowing the reservoir fluid pressure to fall below the bubble point pressure is not advisable as the gas released in the reservoir acts as barriers to free flow of liquid thus reducing the effective permeability to oil. When compared to low shrinkage crude oils, high shrinkage crude oils give off more gas per barrel of reservoir oil produced to the surface for equal pressure drop (𝑃𝑟 − 𝑃𝑠𝑐 ), where 𝑃𝑠𝑐 is pressure at standard condition and 𝑃𝑟 is reservoir pressure. Figure 4.5 below is a typical volatile oil reservoir phase diagram. Critical point S Figure 4.5 Phase Diagram of a Volatile Oil Reservoir [Source: https://www.slideserve.com/cade/types-of-oil-and-gas-reservoirs] 4.4 Types of Natural gas reservoirs Natural gas reservoir are reservoirs which at initial reservoir temperature and pressures, contain wholly gaseous hydrocarbon and no liquid oil. Natural gas reservoirs are categorized into three based on the position of the reservoir temperature and pressure when plotted on a phase diagram. These are: (i) Gas condensate reservoirs, (ii) Wet gas reservoirs and (iii) Dry gas reservoirs. 4.4.1 Gas condensate reservoirs Gas condensate reservoirs are reservoirs which at initial reservoir conditions, have pressures above the dew point pressure and reservoir temperatures greater than the critical temperature, 𝑇𝑐 , but less than the cricondentherm, 𝑇𝑚𝑎𝑥. Thus gas condensate reservoirs plot to the right of the critical point, to the left of the cricondentherm and above the dew point line, at initial reservoir conditions. Figure 4.6 below is a typical phase diagram for a gas condensate reservoir fluid. At initial conditions, position 1, the system is a single phase gas, because the reservoir pressure is greater than the dew point pressure, (𝑃𝑖 > 𝑃𝑑 ). If the reservoir is put on production, the pressure in the reservoir falls isothermally and dew point pressure is approached. At the dew point pressure, position 2, known as the upper dew point, the first drop of liquid condenses from the gas phase to form a liquid phase which remains at equilibrium with the gas in the reservoir. The fact that liquid condenses from a gas phase during declining pressure is contrary to physical laws of nature which requires gas to expand, not condense as pressure decreases on a mass of gas. Therefore, this phenomenon is called, “Retrograde or Abnormal Condensation”. As the pressure in the reservoir falls lower below the dew point pressure, more liquid condenses in the reservoir. The condensation in the reservoir is as a result of the presence of a good fraction of high molecular weight hydrocarbons in the gas condensate fluid which condense to liquids at lower pressure conditions. If the reservoir fluid were to be produced to the surface, the condensation to liquid would occur at the surface and the field operator would gain financially from the sale. Oil prices are in general, higher than gas prices so, optimal operation and production from gas condensate reservoirs are advocated. Natural gas that contains considerable amount of natural gas liquids (ethane plus fractions) are called “rich gas” or “wet gas”. Note this means that gas could be termed wet even if it is not produced from a wet gas reservoir. The increase in liquid formed from gas within the reservoir as pressure falls as a result of production, does not continue indefinitely. At some point, (position 3), the maximum liquid is formed after which the condensed oil begins to re-vapourize with further decline in pressure. Theoretically, if the reservoir is produced to some very low pressure, all of the condensed liquid would re-vapourize, at position 4, known as the lower dew point. At the lower dew point, the last drop of condensed liquid revapourizes to form gas. Thus at both the upper and lower dew points, an infinitesimal amount of liquid is in equilibrium with a seemingly, infinite amount of gas. The liquid, if it condenses in the reservoir is often lost therein because, first, its saturation is below critical saturation required to make the liquid phase mobile, thus producible. Also, the pressure required for complete revapourization of condenses liquid is often below the abandonment pressure, so that, it is not practicable to redeem liquids formed in reservoirs. This is not good for the field engineer who would require the liquid to be brought to the surface where it commands a higher price than gas. Also, allowing condensation of gas in the reservoir has the further disadvantage of decreasing gas productivity at the surface. This is because; the immobile liquid formed within the pores hinder the free flow of gas, by forming barriers, thus diminishing permeability to gas. Methods to Prevent Condensation in the Reservoir It is possible to avoid condensation of gas within the reservoirs by ensuring that gas condensate reservoir pressures do not fall to the dew point pressure during production. One way to achieve this is by practicing intermittent production in which production is carried out at pressures above the dew point pressure, then, as reservoir pressure begins to fall towards the dew point pressure, the wells are closed for a period, to allow for pressure build up before further production would commence. The disadvantage of this is the fact that there is delay in producing the reservoir fluid and thus, a delay in return on investments. Another method that can be used to prevent condensation of gas to liquid in the reservoir is called Gas Cycling. Gas Cycling During gas cycling, dry gas (that is, gas mixture consisting of low molecular weight hydrocarbons) is injected into the reservoir to maintain the reservoir pressure. The gas where it mixes with the reservoir gas, lightens it and the blend is produced to the surface. At the surface, the gas is passed into separators where the high molecular weight constituents separate as liquid by condensation and the light components (𝐶1 𝑎𝑛𝑑 𝐶2 𝑚𝑎𝑗𝑜𝑟𝑙𝑦) which remain as gas, are re- injected. This continues in a cycle up until the produced fluid has almost dry gas composition without the heavier ethane plus (𝐶2+ ) fractions.  Critical Point (𝑷𝒊 , 𝑻𝒊 ) 1 Initial reservoir condition (𝑷𝒄 , 𝑻𝒄 ) 2 Upper Dew Point 3 S % Liquid 4 Lower Dew Point 𝑻𝒎𝒂𝒙 Temperature Figure 4.6 Phase Diagram of a Gas Condensate Reservoir 4.4.2 Wet Gas Reservoirs Wet gas reservoirs are reservoirs with natural gas which at initial reservoir conditions, exist at temperatures above the cricondentherm. Thus, the reservoir fluid remains in the single phase gas throughout the production life of the reservoir, since the pressure falls at a constant temperature (isothermal pressure decline). Thus, no liquid condenses in the reservoir for wet gas reservoirs. However, the fluid being produced to the surface undergoes temperature as well as pressure decline, resulting in surface liquid (condensate) and gas, plotting in the two phase region of the phase envelope. Figure 4.7 illustrates the phase behavior of wet gas reservoir fluids.  Critical Point 1 3 S 2 Dew Point line % Liquid Temperature Figure 4.7 Phase Diagram of a Wet Gas Reservoir For the wet gas reservoir shown in figure 4.7, the initial reservoir conditions occur at position 1, During production, reservoir pressure falls isothermally along path 1 2, which is outside the two phase envelope, so that no liquid is formed in the reservoir. However, for the fluid being produced to the surface, the production path is 1 3 Separator. At position 3, the dew point pressure of the reservoir is attained and the first drop of liquid is formed as the fluid travels from the reservoir to the surface separator, S. The separator is at lower pressure and temperature than at the dew point, so more liquid condenses at the separator, shown within the two-phase region in the phase diagram. The fact that liquid condenses from the gas produced from wet gas reservoirs implies that the gas mixture contains considerable amount of ethane plus fractions (or natural gas liquids). The surface liquid obtained from wet gas reservoirs is less than that from gas condensate reservoirs which implies that the amount of natural gas liquids in gas condensate reservoir fluids exceeds that contained in wet gas reservoir fluids. 4.4.2 Dry Gas Reservoirs Dry gas reservoirs are gaseous hydrocarbon systems with initial reservoir temperatures above the cricondentherm. The reservoir fluids contain poor gas (consisting of gas with very little or no natural gas liquid fractions), consisting majorly of methane and small proportions of ethane and ethane plus fractions. As a consequence, when it is produced to the surface, no liquid is formed or recovered at separator conditions. This implies that the separator conditions plot outside the two-phase envelope as shown in figure 4.8 below. Therefore, not only does the reservoir pressure decline (isothermally), plot outside the two phase envelope, but the path of production to surface conditions of temperature and pressure also plots outside (to the right) of the two phase envelope on the phase diagram. Thus, the reservoir fluid remains in the single gas phase both in the reservoir and at the surface, for its entire production life. Initial reservoir condition 1 Critical Point (𝑷𝒊 , 𝑻𝒊 ) S 2 Dew Point line % Liquid Temperature Figure 4.8 Phase Diagram of a Dry Gas Reservoir