Types of Reservoir
The classification of a hydrocarbon reservoir is basically dependent on the composition of the hydrocarbon mixture in the reservoir, the location of the initial pressure and temperature of the reservoir and the condition at the surface (separator) production pressure and temperature. A hydrocarbon reservoir can be classified as either oil black oil or volatile oil or condensate or natural gas (associated or non-associated) reservoirs. Since the hydrocarbon system has varying fluid compositions, to appropriately classify or identify the type of reservoir system, we need to understand the hydrocarbon phase envelope (pressure-temperature diagram).
1.4.3 Phase Envelope
According to Wikipedia, a phase envelope is a type of chart used to show conditions of pressure, temperature, volume etc at which thermodynamically distinct phases occur and coexist at equilibrium. Figure 1.8 depicts a phase envelope or pressure temperature (PT) phase diagram of a particular fluid system. It comprises of two curves (bubble point and dew point curves) which encloses an area representing the pressure and temperature combinations for which both gas and liquid phases exist; called the two-phase region. The curves or quality lines converging at the critical
point within the two-phase envelope indicate the percentage of liquid at any given pressure and temperature of the total hydrocarbon volume of the reservoir. Furthermore, on the phase envelope, we can place the various types of reservoirs depending on the location of the initial reservoir temperature and pressure with respect to the two-phase. Above the bubble-point curve in Fig. 1.8, we have a single liquid phase called an undersaturated reservoir while at a point beyond the dew point curve; a single gas phase occurs which may be a wet or dry gas reservoir. The various terms on the phase envelope are defined below. 1.4.3.1 Bubble-Point Curve The bubble-point curve is defined as the line separating the liquid-phase region from the two-phase region and above which a single liquid phase exists as shown in Fig. 1.8. Note, if there is gas, it will be dissolved in the liquid. 1.4.3.2 Dew-Point Curve The dew-point curve is defined as the line separating the vapor-phase region from the two-phase region and above which vapor phase exists as shown in Fig. 1.8. 1.4.3.3 Cricondentherm The Cricondentherm (Tct) is defined as the temperature above which there is no existence of two-phase irrespective of the pressure or it can be defined as the maximum temperature above which a single gas phase exist and no liquid can be formed regardless of pressure (Fig. 1.8). The pressure corresponding to cricondentherm is known as the cricondentherm pressure (Pct)
1.4.3.4 Cricondenbar The cricondenbar (Pcb) is defined as the pressure above which there is no existence of two-phase irrespective of the temperature or it can be defined as the maximum pressure above which a single liquid phase exists and no gas can be formed regardless of temperature (Fig. 1.8). The temperature corresponding to cricondenbar is known as the cricondenbar temperature (Tcb). 1.4.3.5 Critical Point The critical point is the point where the bubble point curve, dew point curve and the quality lines converge (Fig. 1.8). At this point, one cannot distinguish between the liquid and gas properties. Hence it is referred to as the state of pressure and 12 1 Introduction temperature at which all intensive properties of the gas and liquid phases are equal. The corresponding pressure and temperature at the critical point are referred to as the critical pressure (Pc) and critical temperature (Tc) of the mixture. 1.4.3.6 Quality Lines These are dash lines enclosed by the bubble-point curve and the dew-point curve. They converge at the critical point. They also describe the pressure and temperature conditions for equal volumes of liquids as shown in Fig. 1.8.
1.4.3.7 Phase Envelope (Two-Phase Region) This is the area enclosed by the bubble-point curve and the dew-point curve, wherein gas and liquid coexist in equilibrium; it is the region where we have the quality lines (Fig. 1.8). That is the region of greater than zero percent (0%) liquid and less than hundred percent (100%) on the phase envelope. 1.4.4 Oil Reservoirs A reservoir can be classified as oil reservoir if the temperature of the reservoir is less than the critical temperature of the reservoir fluid. It can be further classified as a black oil or volatile oil depending on the gravity of the stock tank liquid usually the API of the crude. Also, it can be classified as undersaturated or saturated reservoir based on the location of the initial reservoir pressure. 1.4.4.1 Undersaturated and Saturated Reservoir The fluid in the reservoir is a complex mixture of hydrocarbon molecules and as pressure and temperature reduces; that is the flow of hydrocarbon fluid from the reservoir condition to the surface separator, phase changes occur. Considering an undersaturated and a saturated reservoir as shown in Fig. 1.9 it can be seen that at the initial pressure, the reservoir is represented as a single liquid phase. As the pressure drops from the initial condition to the wellbore as a result of fluids production; the fluid remains as a single phase liquid at the wellbore. Therefore, a reservoir whose temperature is greater than the bubble point pressure is referred to as an "undersaturated reservoir". As the pressure reduces further until it reaches the bubble point pressure (saturated pressure) where the first bubble of gas is evolved from the hydrocarbon mixture, the fluid still remains in a single liquid phase. Below the bubble point pressure, there is a two-phase region and with further reduction in pressure, the fluid is produced up the tubing and the amount of gas evolved increases until it reaches the separator. Thus,
1.4.5 Types of Reservoir Fluids 1.4.5.1 Black Oil Reservoir Figure 1.10 represents a black oil system which is made up of heavy hydrocarbons and non-volatile hydrocarbons. It is characterized by a dark or deep color liquid having initial gas-oil ratios of 500 scf/stb or less, oil gravity between 30 and 40 API. The pressure and temperature conditions existing in the separator indicate a high percentage of about 85% of liquid produced. The oil remains undersaturated within the region above the bubble point pressure, this means that the oil could dissolve more gas if present in the hydrocarbon mixture. At the bubble point pressure, the reservoir is said to be saturated and this implies that the oil contains the maximum amount of dissolved gas and cannot hold any more gas. Further reduction in pressure causes some shrinkage in the volume of oil as it moves from the reservoir (two-phase region) to the surface (separator). Therefore, black oil is often called low shrinkage crude oil or ordinary oil. 1.4.5.2 Volatile Oil Reservoir A volatile oil reservoir is one whose reservoir temperature is below the critical point or critical temperature of the fluid as shown in Fig. 1.11. It contains relatively low
liquid content as it approaches the critical temperature, as compared to black oil reservoir that is far away from the critical point; a volatile oil reservoir is made up of fewer heavy hydrocarbon molecules and more intermediate components (ethane through hexane) than black oils. Volatile oils are generally characterized with Temperature 100% Liquid (Twf Pwf) (Tr, Pr) Volatile oil reservoir Critical point (Tsep, Psep) Separator 0% Liquid 80% Dew point curve Bubble point curve Production path Fluid path in the reservoir Pressure Fig. 1.11 Volatile oil reservoir Temperature 100% Liquid (Twf Pwf) (Tr, Pr) Black oil reservor Critical point (Tsep, Psep) Separator 0% Liquid 80% Dew point curve Bubble point curve Production path Fluid path in the reservoir Pressure Fig. 1.10 Black oil reservoir 1.4 Reservoir Engineering 15 stock tank gravity between 40 and 50 API, with a lighter color (brown, orange, or green) than black oil. In the case of volatile oil, 65% of the reservoir fluid is liquid at the separator condition. This means that relatively large volume of gas is evolved from the hydrocarbon mixture leaving a smaller portion as liquid. It is a high shrinkage oil as compared to black oil. 1.4.5.3 Condensate (Retrograde Gas) A condensate reservoir fluid is a gas at the initial reservoir pressure. It occurs as shown in Fig. 1.12 when the temperature of the reservoir lies between the critical temperature and cricondentherm of the reservoir fluid. It contains lighter hydrocarbons and fewer heavier hydrocarbons than volatile oil, its oil gravity is above 40 API and up to 60 API (i.e. between 40 and 60 API), the gas-oil ratio increases with time due to the liquid dropout, and the loss of heavy components in the liquid whose GOR is up to 70,000 scf/stb, it has about 5–10% liquid at the surface depending on the reservoir. The reservoir fluid is water-white or slightly colored oil at the stock tank. In Fig. 1.12, at the initial condition, the reservoir is in a single gas phase and as the pressure drops, the fluid goes through the dew point which then condenses large volumes of liquid as it passes through the two phase region in the reservoir. Consequently, as the reservoir further depletes and the pressure drops, liquid condenses from the gas to form a free liquid inside the reservoir.
In the production of a gas condensate field, gas is mostly produced with some liquid dropout as the pressure drops below dew point pressure; occurring mostly in the separator and can still be produced in the wellbore which ultimately leads to a restriction in the flow of gas. The temperature and pressure may change once the reservoir fluids enter into the wellbore, thereby causing liquid dropout within the wellbore. Thus, if the gas having the larger fraction does not have enough energy to lift the dropout liquid to the surface, a fallback in the wellbore occurs or liquid loading. If this is continuous, the percentage of the liquid will increase and may eventually restrict the gas production. This challenge can be adequately handled with artificial lift technologies such as gas lift. Table 1.1 shows the comparison of blackoil, volatile and condensate reservoir fluid properties
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