Gas-oil ratio

This section will firstly consider the properties of oils in the reservoir (compressibility, viscosity and density), and secondly the relationship of subsurface to surface volume of oil during the production process (formation volume factor and gas oil ratio). 

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. 

If the reservoir pressure remains above the bubble point then any gas liberated from the oil must be released in the tubing and the separators, and will therefore appear at the surface. In this case the producing gas oil ratio (Rp) will be equal to R. i.e. every stock tank barrel of oil produced liberates Rs scf of gas af surface. 

The producing gas oil ratio starts at the solution GOR, decreases until the critical gas saturation is reached, and then increases rapidly as the liberated gas is produced into the wells, either directly as it is liberated, or pulled into the producing wells from the secondary gas cap. The secondary gas cap expands with time, as more gas is liberated, and therefore moves closer to the producing wells, increasing the likelihood of gas being pulled In from the secondary gas cap. 

B. licheniformis JF-2 and Clostridium acetogutylicum were investigated under simulated reservoir conditions. Sandstone cores were equilibrated to the desired simulated reservoir conditions, saturated with oil and brine, and flooded to residual oil saturation. The waterflood brine was displaced with a nutrient solution. The MEOR efficiency was directly related to the dissolved gas/oil ratio. The principal MEOR mechanism observed in this work was solution gas drive [505]. 

Petroleum and chemical engineers perform oil reservoir simulation to optimize the production of oil and gas. Black-oil, compositional or thermal oil reservoir models are described by sets of differential equations. The measurements consist of the pressure at the wells, water-oil ratios, gas-oil ratios etc. The objective is to estimate through history matching of the reservoir unknown reservoir properties such as porosity and permeability. 

Matching Water-Oil Ratio, Gas-Oil Ratio or Bottom Hole Pressure... 

Similar findings were observed for the gas-oil ratio or the bottom hole pressure of each well which is also a state variable when the well production rate is capacity restricted (Tan and Kalogerakis. 1991). 

In this case the observed data consisted of the water-oil ratios, gas-oil ratios, flowing bottom hole pressure measurements and the reservoir pressures at two locations of the well (layers 7 and 8). In the first run, the horizontal permeabilities of layers 6 to 9 were estimated by using the value of 200 md as the initial guess. 

Figure 18.27 Observed and calculated water-oil ratio and gas-oil ratio for the SPE problem using 7 permeability zones [reprinted from the Journal of the Canadian Petroleum Technology with permission].

Live oil with dissolved methane does not follow the above correlations as methane relaxes by a spin-rotation mechanism, even when dissolved in liquid hydrocarbons [13]. The Ti relaxation time as a function of rj/T is illustrated in Figure 3.6.2 for different gas/oil ratios expressed in units of m3 m-3 as a parameter. The solid line is the fit for zero gas/oil ratio and is given by Eq. (1). 

Fig. 3.6.2 Relaxation time of pure alkanes or methane saturated alkanes as a function of viscosity, temperature and gas/oil ratio (GOR, m3 nT3) [13]. The solid line is for zero GOR. The dashed lines are for the indicated GOR.

Diffusivity correlates linearly with the ratio of temperature and viscosity. Therefore the diffusivity can also be expected to correlate with relaxation time because the latter correlates with temperature and viscosity according to Eq. (3.6.1). Figure 3.6.3 illustrates the correlation between relaxation time and diffusivity with the gas/oil ratio as a parameter [13]. The correlation between diffusivity and relaxation time extends to hydrocarbon components in a mixture and there is a mapping between the distributions of diffusivity and relaxation time for crude oils [17]. 

Figure 7. Comparison between H-Beta zeolites (open circles and dashed lines) and HY zeolites (continuous lines) for gas-oil cracking (a) First-order activity constant by specific surface area vs, Si/Al ratio (b) and (c) Average total conversion vs. gas-oil ratio for a H-Beta with Si/Al=27 and a HY Si/Al=35, and for a H-Beta with Si/Al=10 and a Hy with Si/Al=7.7 respectively. Solid circles correspond to the H-Beta steamed at 750 C and 1 atmosphere of water pressure.

Reducing vessel size depends on the gas-oil ratio and the pressure level of gas compression. Two smaller vertical vessels—one servicing a high-pres- sure relief header and one servicing g a low-pressure relief header—will oc- 4 cupy less space than one large low-pressure relief drum., ... 

The higher selectivity it would require in platform separation facilities will make the economics of developing all fields lees favorable at the same gas price, and marginal fields might not be developed. Gas-condensate fields with high gas-oil ratios, in particular, would be more likely to be marginal if faced with a low dewpoint specification. 

Overall, horizontal vessels arc more economical for normal oil and gas separation, particularly where there may be problems with emulsions, foam or high gas-oil ratios. Vertical vessels work more effectively in either low or very high GOR applications, such as scrubbers. 

If all three indicators—initial gas-oil ratio, stock-tank liquid gravity, and stock-tank liquid color—do not fit within the ranges given in the rules of thumb, the rules fail and the reservoir fluid must be observed in the laboratory to determine its type. 

As a practical matter, when producing gas-oil ratio is above 50,000 scf/STB, the quantity of retrograde liquid in the reservoir is very small and the reservoir fluid can be treated as if it were a wet gas (defined later). 

Producing gas-oil ratios for a retrograde gas will increase after production begins when reservoir pressure falls below the dew-point pressure of the gas. 

An initial producing gas-oil ratio of 3300 to 5000 scf/STB indicates a very rich retrograde gas, one which will condense sufficient liquid to fill 35 percent or more of the reservoir volume. Even this quantity of liquid seldom will flow and normally cannot be produced. 

The surface gas is very rich in intermediates and often is processed to remove liquid propane, butanes, pentanes, and heavier hydrocarbons. These liquids often are called plant liquids. The gas-oil ratios in the rules of thumb discussed above do not include any of these plant liquids. 

The average gas-oil ratio produced from the Upper Washita-Fredericksburg formation of the Summerland Field is 275 scf/STB. The gravity of the produced oil is 26°API. The color of the stock-tank oil is black. What type of reservoir fluid is in this formation ... 

One of the wells in the Merit Field, completed in December 1967 in the North Rodessa formation, originally produced 54°API stock-tank liquid at a gas-oil ratio of about 23,000 scf/STB. During July 1969, the well produced 1987 STB of 58°API liquid and 78,946 Mscf of gas. In May 1972, the well was producing liquid at a rate of about 30 STB/d of 59°API liquid and gas at about 2000 Mscf/d. What type of reservoir fluid is this well producing ... 

A field in north Louisiana discovered in 1953 and developed by 1956 had an initial producing gas-oil ratio of 2000 scf/STB.3 The stock-tank liquid was medium orange and had a gravity of 51.2°API. Classify this reservoir fluid. 

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