DENSITY data are reported on 16 saturated is the use of the ideal gas law corrected by a hydrocarbon vapors at pressures ranging from compressibility factor. The method pro-1000 to 8220 lb. per sq. in. and at temperatures posed by K ay 7 of correlating compresranging from 35° to 250°F. These data have sibility factors for gaseous mixtures on been used to extend the compressibility-factor chart for natural gases up to !O,ooo lb. per pseudocritical properties 5 appears to be sq. in. The relatively large quantity of high-satisfactory for natural gases. 2 The methboiling constituents present in high-pressure ane-compressibility factor has been shown vapors in equilibrium with crude oils makes it to deviate systematically from the behavior necessary to include in the analysis of the gas of natural gases 2 and a chart giving these the molecular weight, density, and possibly corrected factors is available. boiling range of the heptanes and heavier A method of computing specific volume fraction. Relationships have been presented by of gaseous mixtures from partial molal which the density of gases may be obtained volumes has been reported by Sage and directly from the temperature, pressure, and L 8 C i t d t f th t t' acey. omp e e a a or e compu a IOn gas gravity provided the gases have a common source or are similar in composition.are not yet available for all hydrocarbon

The dimensionless inflow performance relationship (IPR) for solution-gas drive wells presented by Vogel* is very useful in well producibility calculations. Well rates at various pressure drawdowns can be predicted easily by use of either his chart or his equation (his Fig. 5 and Eq. 1). A second use of his relationship, to be illustrated later, is as a means of averaging results of several rate tests on a given well. Vogel investigated effects of wellbore damage on the shape of IPR curves. He states that the effect of skin, or damage, is to cause a straightening of the IPR curve. The reference curve he presents, however, (his Fig. 5) essentially applies to wells without damage during their early life. My purpose here is to present a companion chart that can be used for calculations involving damaged wells. The chart is useful in predicting stimulation that might be accomplished, under predicting stimulation that might be accomplished, under given drawdowns, if the wellbore damage is changed from one value to some other value. Consider the pressure-distance profile of the positively damaged well illustrated in Fig. 1. The flow positively damaged well illustrated in Fig. 1. The flow efficiency, FE, of the well-formation system is given by the relationship(1) Graphically, this amounts to the distance (p - p' wf) divided by the distance (p - p wf). For a well draining a closed cylindrical volume, flow efficiency can also be expressed as (2) where s is the dimensionless skin factor. FE also expresses the ratio of the well's flow rate with damage to the flow rate without damage. P. 1399

Estimating probable flow rates of wells producing from solution gas drive reservoirs is a problem frequently encountered by petroleum engineers. One approach to an answer involves the simultaneous solution of the well's inflow performance relationship (IPR) and the rate-dependent pressure losses in the well tubing, surface flow lines, and chokes. Nind covers very nicely several graphical methods of accomplishing the simultaneous solution. This note presents relationships that can be used to obtain IPR presents relationships that can be used to obtain IPR curves applicable to bounded solution gas drive reservoirs in which the average reservoir pressure is less than the reservoir fluid bubble-point pressure. Vogel's dimensionless IPR equation is the basis for the development. An example illustrates how future IPR curves can be developed from a current productivity index value. Vogel developed a general dimensionless relationship for wells producing under conditions outlined above and under pseudosteady-state conditions given by Eq. 1. (1) =  1 - 0 .2 - 0 .8  , where qo = stock-tank oil producing rate, B/D pwf = wellbore flowing pressure, psi pwf = wellbore flowing pressure, psip = average reservoir pressure, psi p = average reservoir pressure, psi qo max = maximum rate the well would producefor conditions of pwf = 0. Eq. 1 can be rearranged to = ...............(2) The productivity index of a well is defined by (3) J  = Substitution of Eq. 3 into Eq. 2 yields (4) J  = Physical conditions inherent in Eq. 4 are that reservoir Physical conditions inherent in Eq. 4 are that reservoir gas and oil saturations, as well as reservoir pressure, vary with distance away from the wellbore, and that the well's skin factor is zero. Let us now consider the situation in which fluid saturations are the same everywhere in the reservoir. This is analogous to a "zero drawdown" situation. Let J* be the well's productivity index under these conditions. Mathematically, (5) lim J J*  = Applying the limit conditions to Eq. 4 yields (6) J*  = P. 1141

Density data are reported on 15 saturated hydrocarbon liquids in the rangeof 35? to 250?F. and 1000 to 8220 lb. per sq. in. The apparent liquid densitiesof methane and ethane are shown to vary with the density of the system in whichthey are present. A method is proposed whereby the densities of liquidhydrocarbon mixtures containing both methane and ethane in solution may becomputed at elevated temperature and pressures within the accuracy of usualengineering computations. A method of computing the shrinkage of crude oilsbased upon the gas-oil ratio, gas analysis, and crude gravity is outlined. Introduction The densities of naturally occurring liquid hydrocarbon mixtures areimportant in many petroleum engineering computations. Calculation of theshrinkage of a subsurface sample of crude oil as the natural gas is evolved isone example of the use of liquid-density data. Sage, Hicks, and Lacey have presented a method of computing the density ofhydrocarbon liquid mixtures based on partial molal volumes. Katz has indicateda method based on the principle of additive volumes of the components and usingapparent densities for methane and ethane. T.P. 1397

The recovery of the heavier components from a gas cap or retrograde pool isshown to be the greatest when the sand is cycled with a dry gas at a lowpressure. This conclusion is in direct opposition to the belief that the mostefficient production program is pressure maintenance and cycling at or near thedew point. The results are calculated from:constant volume, variable compositionpressure-volume-temperature tests on a mixture of trap gas and liquid from aproducing well;published equilibrium constant data and the measuredcomposition of the dew-point material; andthe fact that in a sand sectionof homogeneous permeability, injected gas displaces reservoir gas nearlyquantitatively. The results are based on the simplifying assumption that variable permeabilitysystems may be defined by the ratio of two statistical parameters, and that gasinjected into an actual sand will behave as though the sand were composed ofmany layers, each of constant permeability. Introduction Pressure decline in gas-condensate type reservoirs is accompanied by theformation of a liquid phase throughout the reservoir. Over the past ten yearsthe processing of the material from these types of reservoirs for the heavierhydrocarbon components and the return of the light fraction to the reservoir("cycling") has become increasingly popular. It has often been stated that thepurpose of such a program is to prevent the loss of the retrograde liquid phaseformed in the reservoir. The purpose of this paper is to present the results of laboratory tests andcomputations concerned with several possible methods of producing a gas cap orcondensate type of reservoir. The results show that the recovery of heavier hydrocarbons for this type ofreservoir is not a maximum under conditions of cycling at or near the dew-pointpressure. Instead, variations in permeability and the ability of the dryinjected gas to revaporize condensate, point to cycling at a considerablyreduced pressure as the optimum production-method. In addition the papersuggests a way of evaluating sands for their permeability variation. The calculations presented in the following sections of the paper are in termsof the production of the butanes and heavier fraction from the gas gap of afield which had an original pressure of approximately 3000 psi. T.P. 2200