A I,500-ft experimental well was used to study the pressure gradients occurring during continuous, vertical, twophase flow through I-in., 114-in. and Ii/j-in. nominal size tubing. The test well was equipped with two gas-lift valves and four Maihak electronic pressure transmitters as well as with instruments to measure the liquid production rate, air injection rate, temperatures and surface pressures. Tests were conducted for widely varying liquid flow rates, gas-liquid ratios and liquid viscosities. From these data, an accurate pressure-depth traverse was constructed for each test in each of the three tubing sizes. From the results of these tests, correlations have been developed which allow the accurate prediction of flowing pressure gradients for a wide variety of tubing sizes, flow conditions, and liquid properties. Also, the correlations and equations which are developed satisfy the necessary condition that they reduce to the relationships appropriate to single-phase flow when the flow rate of either the gaj or the liquid phase becomes zero. All the correlations involve only dimensionless groups, which is a condition usually sought for in similarity analysis but not always achieved. The correlations developed in this study have been used to calculate pressure gradients for pipes of larger diameter than those upon which the correlations are based. Comparisons of these calculated gradients with experimentally determined gradients for the same flow conditions obtained from the literature indicate that extrapolation to these larger pipe sizes is possible with a degree of accuracy sufficient for engineering calculations. The extent of this extrapolation can only be determined with additional data from larger pipe diameters.
A previously published model describing pressure-buildup behavior of naturally flaetured reservoirs was combined }t'itha nonlinear, least-squares regression technique to analyze buildup data. The model adequately described the buildup response and was useful for obtaining effect ive formation permeability in the cases studied.
Continuous, two phase flow tests have been conducted during which four liquids of widely differing viscosities were produced by means of air-lift through 1¥.! -in. tubing in a 1,500-ft. experimental well. The purpose of these tests was to determine the effect of liquid viscosity on two-phase flowing pressure gradients.The experimental test well was equipped with two gas-lift valves and four Maihak electronic pressure transmitters as well as instruments to accurately measure the liquid production, air injection rate, temperatures, and surface pressures.The tests were conducted for liquid flow rates ranging from 30 to 1,680 B/D at gas-liquid ratios from 0 to 3,-270 scfl bbl. From these data, accurate pressure-depth traverses have been constructed for a wide range of test conditions.As a result of these tests, it is concluded that viscous effects are negligible for liquid viscosities less than 12 cp, but must be taken into account when the liquid viscosity is greater than this value. A correlation based on the method proposed by Poettmann and Carpenter and extended by Fancher and Brown has been developed for 1¥.! -in. tubing, which accounts for the effects of liquid viscosity where these effects are important.
This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 30 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Hydrocarbon saturation and its distribution within a reservoir are important parameters in reservoir engineering calculations. One method often used to obtain these data is direct measurement on cores taken from the interval of interest. However, such measurements on conventional cores may result in incorrect values for one or both of two reasons:some hydrocarbon may be flushed from the core by mud filtrate invasion during coring, andfluids may be driven from the core by gas expansion as pressure is reduced during surfacing. Pressure coring is designed to en the latter by maintaining pressure on the core as it is retrieved. This paper summarizes our experience with pressure coring. Design of the present pressure pressure coring. Design of the present pressure core barrel is reviewed, and current operating procedures and core handling and analysis procedures and core handling and analysis techniques are discussed. Field experience is summarized by describing a variety of specific applications. Introduction Knowledge of both hydrocarbon volume and its distribution within a reservoir is important for estimating reserves and for planning commercial development. Ideally, one would like to obtain samples from the formation of interest in their original state and measure saturations directly. Such measurements on conventional cores, however, may result in incorrect values for one or both of two primary reasons:some hydrocarbon may be flushed from the core by mud filtrate invasion during the coring operation, andadditional fluids may be driven from the core by expanding gas as the pressure is reduced during surfacing. Under some conditions, flushing by mud filtrate can be minor; if this is the case, valid fluid saturations can often be obtained using a pressure-retaining core barrel to prevent loss pressure-retaining core barrel to prevent loss of fluids by gas expansion. Laboratory observations suggest that significant reduction in oil saturation by gas expansion is more likely to occur in water-wet cores than in mixed-wettability or oil-wet cores. At low oil saturation, the capillary forces in mixed-wettability or oil-wet cores will inhibit expulsion of oil by gas whereas this would not be the case for water-wet cores. This behavior suggests that the use of a pressure-retaining core barrel should be particularly beneficial for coring water-wet formations. The use of a pressure-retaining core barrel is certainly not new. The first design for and application of such a core barrel was reported by Sewell of Carter oil Company in 1939.
A recent correlation for multiphase vertical flow by Hagedorn and Brown1has been used to examine the effect of numerous variables such as pipe size, gas-liquid ratio, liquid flow rate, liquid viscosity, liquid surface tension, oil API gravity, water cut, etc., on flowing pressure gradients. Most previous correlations were derived by using a form of the generalenergy equation which assumed negligible changes in kinetic energy. Undercertain flow conditions this can lead to serious errors in predicting pressuretraverses. Examples of traverses calculated both with and without the kineticenergy term are included here. The Chew and Connally correlation for calculating change, in viscositywith changing pressure and temperature has been extended so that the effect ofa changing viscosity with depth on pressure gradients can also bepredicted. Examples illustrating the effect of tubing size show the importance ofthis correlation in determining pipe sizes for initial well completions. Limitations on production rates in small pipe sizes from excessive frictionlosses can be predicted with greater accuracy. The combined use of a vertical-flow correlation with a horizontal-flowcorrelation provides a method for determining the maximum flow rate possiblefrom both flowing and gas-lift wells. Examples are included to illustrate application of the combined use ofvertical and horizontal-flow correlations in optimizing production rates andminimizing excessive costs from over injection of gas in gas-liftwells. INTRODUCTION The problems of multiphase vertical and horizontal flow are immediatelyencountered in any producing well. Fig. 11 shows three stages ofproduction: flow in porous medium, vertical flow and horizontal flow. All threestages affect the production rate from a well. If we are confronted with a particular well and consider only the variablesinvolved in the vertical and horizontal stages of Fig. 1, we should be capableof calculating the flowing bottom-hole pressure necessary to produce aparticular flow rate. A change in any of the variables results in a newsolution to the problem. Recent approaches in developing horizontal and vertical-flow correlationshave improved to the extent that the solution can now be obtained with moreconfidence than previously.
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