Gas solutions

A volatile oil contains a relatively large fraction of lighter and intermediate oomponents which vaporise easily. With a small drop in pressure below the bubble point, the relative amount of liquid to gas in the two-phase mixture drops rapidly, as shown in the phase diagram by the wide spacing of the iso-vol lines. At reservoir pressures below the bubble point, gas is released In the reservoir, and Is known as solution gas, since above the bubble point this gas was contained in solution. Some of this liberated gas will flow towards the producing wells, while some will remain in the reservoir and migrate towards the crest of the structure to form a secondary gas cap. 

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. 

Unlike gases, liquid viscosity decreases as temperature increases, as the molecules move further apart and decrease their internal friction. Like gases, oil viscosity increases as the pressure increases, at least above the bubble point. Below the bubble point, when the solution gas is liberated, oil viscosity increases because the lighter oil components of the oil (which lower the viscosity of oil) are the ones which transfer to the gas phase. 

The above equation introduces two new properties of the oil, the formation volume factor and the solution gas oil ratio, which will now be explained. 

As the reservoir pressure drops from the initial reservoir pressure towards the bubble point pressure (PJ, the oil expands slightly according to its compressibility. However, once the pressure of the oil drops below the bubble point, gas is liberated from the oil, and the remaining oil occupies a smaller volume. The gas dissolved in the oil is called the solution gas, and the ratio of the volume gas dissolved per volume of oil is called the solution gas oil ratio (Rg, measured in scf/stb of sm /stm ). Above the bubble point, Rg is constant and is known as the initial solution gas oil ratio (Rgj), but as the pressure falls below the bubble point and solution gas is liberated, Rg decreases. The volume of gas liberated is (Rg - Rg) scf/stb. 

As solution gas is liberated, the oil shrinks. A particularly important relationship exists between the volume of oil at a given pressure and temperature and the volume of the oil at stock tank conditions. This is the oil formation volume factor (B, measured in rb/stb or rm /stm ). 

Keywords compressibility, primary-, secondary- and enhanced oil-recovery, drive mechanisms (solution gas-, gas cap-, water-drive), secondary gas cap, first production date, build-up period, plateau period, production decline, water cut, Darcy s law, recovery factor, sweep efficiency, by-passing of oil, residual oil, relative permeability, production forecasts, offtake rate, coning, cusping, horizontal wells, reservoir simulation, material balance, rate dependent processes, pre-drilling. 

Solution gas drive (or depletion drive) Gas cap drive Water drive with a large underlying aquifer Undersaturated oil (no gas cap) Saturated oil with a gas cap Saturated or undersaturated oil... 

Solution gas drive occurs in a reservoir which contains no initial gas cap or underlying active aquifer to support the pressure and therefore oil is produced by the driving force due to the expansion of oil and connate water, plus any compaction drive.. The contribution to drive energy from compaction and connate water is small, so the oil compressibility initially dominates the drive energy. Because the oil compressibility itself is low, pressure drops rapidly as production takes place, until the pressure reaches the bubble point. 

Once the bubble point is reached, solution gas starts to become liberated from the oil, and since the liberated gas has a high compressibility, the rate of decline of pressure per unit of production slows down. 

The characteristic production profile for a reservoir developed by solution gas drive is shown in Figure 8.3. 

Figure 8.3 Production profile for solution gas drive reservoir...

In the solution gas drive case, once production starts the reservoir pressure drops very quickly, especially above the bubble point, since the compressibility of the system is low. Consequently, the producing wells rapidly lose the potential to flow to surface, and not only is the plateau period short, but the decline is rapid. 

Commonly the wafer cuf remains small in solution gas drive reservoirs, assuming that there is little pressure support provided by the underlying aquifer. Water cut is also referred to as BS W(base sediment and water), and is defined as ... 

As solution gas drive reservoirs lose pressure, produced GORs increase and larger volumes of gas require processing. Oil production can become constrained by gas handling capacity, for example by the limited compression facilities. It may be possible to install additional equipment, but the added operating cost towards the end of field life is often unattractive, and may ultimately contribute to increased abandonment costs. 

The well is then opened, the CO2 provides a solution gas drive, and oil mobilized by the CO2 soak is produced. 

J. M. Gossett and A. H. Lincoff, Solute Gas Equilibriums in Multi-organicMqueous Systems, report 1981, AEOSR-TR-81-0858 order no. AD-A109082, NTIS, 1981. 

It is important to understand that when chemical reactions are involved, this definition of Cl is based ou the driving force defined as the difference between the couceutratiou of un reacted solute gas at the interface and in the bulk of the liquid. A coefficient based ou the total of both uureacted and reached gas could have values. smaller than the physical-absorption mass-transfer coefficient /c . 

In order to define completely the solubility of a gas in a liquid, it generally is necessary to state the temperature, the equilibrium partial pressure of the solute gas in the gas phase, and the concentration of the solute gas in the liquid phase. Stric tly speaking, the total pressure on the system also should be stated, but for low total pressures, less than about 507 kPa (5 atm), the solubihty for a particular partial pressure of solute gas normally will be relatively independent of the total pressure of the system. 

For quite a number of gases, Henry s law holds very well when the partial pressure of the solute is less than about 100 kPa (I atm). For partial pressures of the solute gas greater than 100 kPa, H seldom is independent of the partial pressure of the solute gas, and a given value of H can be used over only a narrow range of partial pressures. There is a strongly nonlinear variation of Heniy s-law constants with temperature as discussed by Schulze and Prausnitz [2nd. Eng. Chem. Fun-dam., 20,175 (1981)]. Consultation of this reference is recommended before considering temperature extrapolations of Henry s-law data. 

Calculation of Liquid-to-Gas Ratio The minimum possible liquid rate is readily calculated from the composition of the entering gas and the solubility of the solute in the exit liquor, saturation being assumed. It may be necessaiy to estimate the temperature of the exit liquid based on the heat of solution of the solute gas. Values of latent and specific heats and values of heats of solution (at infinite dilution) are given in Sec. 2. 

Overview One of the most important considerations involved in designing gas-absorption towers is to determine whether or not temperatures will vaiy along the length of the tower because of heat effects, since the sohibility of the solute gas normally depends strongly upon the temperature. When heat effects can be neglected, computation of the tower dimensions and required flows is relatively straight-... 

Note that H is simply Henry s constant corrected for units. When the solute gas is readily soluble in the liquid solvent, Henry s law constant (H or H ) is small and Kj approximately equals k, and the absorption process is controlled by the gas film resistance. For systems where the solute is relatively insoluble in the liquid, H is large and K( approximately equals k, and the absorption rate is controlled by the liquid phase resistance. In most systems, the solute has a high solubility in the solvent selected, resulting in the system being gas film resistance controlled. 

Where FCl is the solute gas-liquid partition coefficient, r is the tendency of the solvent to interact through k- and n-electron pairs (Lewis basicity), s the contribution from dipole-dipole and dipole-induced dipole interactions (in molecular solvents), a is the hydrogen bond basicity of the solvent, b is its hydrogen bond acidity and I is how well the solvent will separate members of a homologous series, with contributions from solvent cavity formation and dispersion interactions. 

Associated gas is natural gas found in contact with oil accumulations in the same reservoir. This gas may be dissolved in the oil under reservoir temperatures and pressure (solution gas) or may form a cap of free gas above the oil in the reservoir (gas cap gas). 

We are all familiar with liquid solutions. Gas and solid solutions also exist. We shall consider them briefly and then return to liquid solutions, the most important from a chemist s point of view. 

The equilibria between clathrate and gas, and Qa, clathrate, and gas could be determined by using w-propanol as the auxiliary solvent.53 In the latter equilibrium, the composition of the clathrate is found from the amount of gas required for the conversion of a given amount of solid a-hydroquinone suspended in the propanol solution into clathrate at constant temperature and pressure. The dissociation pressure of the clathrate is given by the total pressure of the four-phase equilibrium -clathrate-solution-gas, corrected for the vapor pressure of w-propanol saturated with a-hydroquinone. Using this technique it was found that the equilibrium clathrates of hydroquinone and argon have yA = 0.34 at 25°C63 and 0.28 at 60°C.28... 

Equilibrium of a gas standing over its saturated solution n0mo, ngni nfmo solution gas. 

In a packed absorption column, the flow pattern is similar to that in a packed distillation column but the vapour stream is replaced by a mixture of carrier gas and solute gas. The solute diffuses through the gas phase to the liquid surface where it dissolves and is then transferred to the bulk of the liquid. In this case there is no mass transfer of the carrier fluid and the transfer rate of solute is supplemented by bulk flow. 

The advantage of using the transfer unit in preference to the transfer coefficient is that the former remains much more nearly constant as flow conditions are altered. This is particularly important in problems of gas absorption where the concentration of the solute gas is high and the flow pattern changes in the column because of the change in the total rate of flow of gas at different sections. In most cases the coefficient is proportional to the flowrate raised to a power slightly less than unity and therefore the HTU is substantially constant. 

In a gas absorption process, the solute gas A diffuses into a solvent liquid with which it reacts. The mass transfer is one of steady state unidirectional molecular diffusion and the concentration of A is always sufficiently small for bulk flow to be negligible. Under these conditions the reaction is first order with respect to the solute A. 

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