Oil reservoir

When the pressure of a volatile oil or black oil reservoir is above the bubble point, we refer to the oil as undersaturated. When the pressure is at the bubble point we refer to it as saturated oil, since if any more gas were added to the system it could not be dissolved in the oil. The bubble point is therefore the saturation pressure for the reservoir fluid. 

An oil reservoir which exists at initial conditions with an overlying gas cap must by definition be at the bubble point pressure at the interface between the gas and the oil, the gas-oil-contact (GOC). Gas existing in an initial gas cap is called free gas, while the gas in solution in the oil is called dissolved or solution gas. 

In gas reservoir engineering, the gas expansion factor, E, is commonly used. However, in oil reservoir engineering it is often more convenient to refer to the gas formation volume factor which is the reciprocal E, and is expressed in units of scf/stb (using field units). The reason for this will become apparent in Section 8. 

The value of the compresjiibility of oil is a function of the amount of dissolved gas, but is in the order of 10 x 10" psi" By comparison, typical water and gas compressibilities are 4x10" psi" and 500 x 10" psi" respectively. Above the bubble point in an oil reservoir the compressibility of the oil is a major determinant of how the pressure declines for a given change in volume (brought about by a withdrawal of reservoir fluid during production). 

For example in estimating the ultimate recovery (UR) for an oil reservoir, one would need to use the following variables ... 

Reservoir engineers describe the relationship between the volume of fluids produced, the compressibility of the fluids and the reservoir pressure using material balance techniques. This approach treats the reservoir system like a tank, filled with oil, water, gas, and reservoir rock in the appropriate volumes, but without regard to the distribution of the fluids (i.e. the detailed movement of fluids inside the system). Material balance uses the PVT properties of the fluids described in Section 5.2.6, and accounts for the variations of fluid properties with pressure. The technique is firstly useful in predicting how reservoir pressure will respond to production. Secondly, material balance can be used to reduce uncertainty in volumetries by measuring reservoir pressure and cumulative production during the producing phase of the field life. An example of the simplest material balance equation for an oil reservoir above the bubble point will be shown In the next section. 

Gas reservoirs are produced by expansion of the gas contained in the reservoir. The high compressibility of the gas relative to the water in the reservoir (either connate water or underlying aquifer) make the gas expansion the dominant drive mechanism. Relative to oil reservoirs, the material balance calculation for gas reservoirs is rather simple. A major challenge in gas field development is to ensure a long sustainable plateau (typically 10 years) to attain a good sales price for the gas the customer usually requires a reliable supply of gas at an agreed rate over many years. The recovery factor for gas reservoirs depends upon how low the abandonment pressure can be reduced, which is why compression facilities are often provided on surface. Typical recovery factors are In the range 50 to 80 percent. 

The primary drive mechanism for gas field production is the expansion of the gas contained in the reservoir. Relative to oil reservoirs, the material balance calculations for gas reservoirs is rather simple the recovery factor is linked to the drop in reservoir pressure in an almost linear manner. The non-linearity is due to the changing z-factor (introduced in Section 5.2.4) as the pressure drops. A plot of (P/ z) against the recovery factor is linear if aquifer influx and pore compaction are negligible. The material balance may therefore be represented by the following plot (often called the P over z plot). 

The recovery factors for oil reservoirs mentioned in the previous section varied from 5 to 70 percent, depending on the drive meohanism. The explanation as to why the other 95 to 30 percent remains in the reservoir is not only due to the abandonment necessitated by lack of reservoir pressure or high water cuts, but also to the displacement of oil in the reservoir. 

The field unit for permeability is the Darcy (D) or millidarcy (mD). For clastic oil reservoirs, a good permeability would be greater than 0.1 D (100 mD), while a poor permeability would be less than 0.01 D (10 mD). For practical purposes, the millidarcy is commonly used (1 mD = 10" m ). For gas reservoirs 1 mD would be a reasonable permeability because the viscosity of gas is much lower than that of oil, this permeability would yield an acceptable flowrate for the same pressure gradient. Typical fluid velocities in the reservoir are less than one metre per day. 

Like steam injection, in-situ combustion is a thermal process designed to reduce oil viscosity and hence improve flow performance. Combustion of the lighter fractions of the oil in the reservoir is sustained by continuous air injection. Though there have been some economic successes claimed using this method, it has not been widely employed. Under the right conditions, combustion can be initiated spontaneously by injecting air into an oil reservoir. However a number of projects have also experienced explosions in surface compressors and injection wells. 

Koopal and co-workers [186] have extended this thermodynamic analysis to investigate the competitive wetting of a solid by two relatively immiscible liquids. They illustrate the tendency of silica to be preferentially wet by water over octane, a phenomenon of importance in oil reservoirs. 

Oil reservoirs are layers of porous sandstone or carbonate rock, usually sedimentary. Impermeable rock layers, usually shales, and faults trap the oil in the reservoir. The oil exists in microscopic pores in rock. Various gases and water also occupy rock pores and are often in contact with the oil. These pores are intercoimected with a compHcated network of microscopic flow channels. The weight of ovedaying rock layers places these duids under pressure. When a well penetrates the rock formation, this pressure drives the duids into the wellbore. The dow channel size, wettabiUty of dow channel rock surfaces, oil viscosity, and other properties of the cmde oil determine the rate of this primary oil production. 

The pressure/composition requirement for miscibility limits the oil reservoirs in which this technology has been appHed. However, the low iajected fluid viscosity often results in poor volumetic sweep efficiency. 

Gas injection into a gas cap overlaying an oil reservoir is considered an EOR method. The resulting repressurization of the reservoir promotes additional oil production. Reinjection of natural gas is responsible for a significant fraction of Alaskan North Slope oil production. 

Eig. 2. Cychc steam stimulation of an oil well (a) steam, injected into a well over a period of days or weeks in a heavy oil reservoir, introduces heat (huff) that, coupled with (b), alternate soak periods lasting a few days to allow (c) a production phase of weeks or months (puff), thins the oil. This process may... 

High temperature steam cools and eventually condenses as it propagates through the oil reservoir. To maintain foam strength as the steam cools, a noncondensible gas, usually nitrogen or methane, is often added to the injectant composition (196). Methods of calculating the optimum amount of noncondensible gas to use are available (197). 

The in situ combustion method of enhanced oil recovery through air injection (28,273,274) is a chemically complex process. There are three types of in situ combustion dry, reverse, and wet. In the first, air injection results in ignition of cmde oil and continued air injection moves the combustion front toward production wells. Temperatures can reach 300—650°C. Ahead of the combustion front is a 90—180°C steam 2one, the temperature of which depends on pressure in the oil reservoir. Zones of hot water, hydrocarbon gases, and finally oil propagate ahead of the steam 2one to the production well. 

The oil 2one is fairly cool, and in a viscous oil reservoir this can result in Htde oil movement (Uquid blocking). Reverse combustion, in which oil ignition occurs near the production well, can avoid this problem. The combustion 2one moves countercurrent to the flow of air from the injection well. Oil flows through heated rock and remains mobile. Reverse combustion requires more air and consumes more oil than forward combustion. 

Petroleum Recovery. Steam is iajected iato oil wells for tertiary petroleum recovery. Steam pumped iato the partly depleted oil reservoirs through iaput wells decreases the viscosity of cmde oil trapped ia the porous rock of a reservoir, displaces the cmde, and maintains the pressure needed to push the oil toward the production well (see Petroleum, enhanced recovery). Steam is also used ia hot-water extractioa of oil from tar sands (qv) ia the caustic conditioning before the separatioa ia a flotatioa tank (35). 

Amoco developed polybutene olefin sulfonate for EOR (174). Exxon utilized a synthetic alcohol alkoxysulfate surfactant in a 104,000 ppm high brine Loudon, Illinois micellar polymer small field pilot test which was technically quite successful (175). This surfactant was selected because oil reservoirs have brine salinities varying from 0 to 200,000 ppm at temperatures between 10 and 100°C. Petroleum sulfonate apphcabdity is limited to about 70,000 ppm salinity reservoirs, even with the use of more soluble cosurfactants, unless an effective low salinity preflush is feasible. 

Differential pressure aeross die lube oil filter Differential pressure aeross die inlet sereen Pressure behind die expander and eompressor impellers Oil reservoir level... 

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