Water coning is the mechanism in which the oil/gas -water contact locally rises toward the perforated interval in a partially penetrated oil/gas well.Numerical and physical models have been built to study the performance of water coning under different boundary conditions. A fully implicit, strongly coupled mathematical model was formulated to handle rapid pressure-saturation changes. On the other hand, a plexiglass model was constructed to obtain a qualitative and quantitative description of water-coning phenomenon. An analytical description of water coning under different flow conditions was developed.

Predicting the advancement of a gas/water contact (OWC) in a waterdrive gas reservoir plays an important role in evaluating, forecasting, and analyzing the reservoir performance. This study was conducted to predict the behavior and the rise of the OWC, assuming that it remains horizontal, and to determine its effect on ultimate gas recovery. Several factors control the rise of the OWC. Some of the most important factors are the size of the aquifer, gas production rate, initial reservoir pressure, and formation permeability. These factors account for the abandonment of a number of gas reservoirs at extraordinarily high pressure.Several methods have been developed for predicting the volume of water influx into a reservoir; the van Everdingen-Hurst method is used in this study. The performance calculated in this study was based on the material-balance equation for gas reservoirs. The gas reservoir pressure was adjusted to the original OWC for the water-influx equation, and the trapped gas in the water-invaded zone was accounted for in the water-invaded region. A constant reservoir permeability of 300 md was used in all calculations. The results showed that when r a lr g s2, the effect of the aquifer on gas reservoir performance can be neglected. Also, the rate at which the OWC advances is controlled by the aquifer size when rairg > 2. Finally, regardless of the size of the reservoir, when r a lr(l>2, the pressure in the unsteady-state water-influx equation has to be corrected to the original owe. Failure to do so may result In an error of more than 100% in the cumulative water influx, which in turn could lead to the wrong conclusions regarding the performance of the gas reservoir.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 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 request 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 The potential distribution around perforations, as a function of perforation penetration, in cased and perforated wells has been determined for several perforation patterns using an electrolytic model. Ideal perforations were simulated. Additionally, the distance from the well bore at which radial flow exists was determined so that the potential (pressure) distributions around an ideal perforation would not be influenced by assumed boundary conditions. Flow lines are perpendicular to the measured equipotential surfaces. Introduction The performance of well perforations has been of concern since the initial advent of gun perforating, in 1932. The importance of be perforation/formation flow relationship has increased as the usage of perforations to complete wells has increased and the use of such techniques as pressure build-up, pressure draw-down, pulse testing and sand control play a pressure draw-down, pulse testing and sand control play a more important role in well completions. The potential distribution as determined in this study define the flow lines (perpendicular to the equipotential surfaces) in the formation. Flow in a reservoir at a great distance from the well bore is radial. That is it converges upon the wellbore as if it were a sink. If the well is completed openhole -all the way through the formation and the formation is isotropic and homogenous, radial flow will occur everywhere in the reservoir. When a perforation exists in a thin zone or many perforations have been made in a thick zone, the flow becomes perforations have been made in a thick zone, the flow becomes nonradial at some distance from the wellbore. Our experiments show that the flow patterns change significantly near the perforated casing. Figure 1 shows the type of flow patterns that perforated casing. Figure 1 shows the type of flow patterns that develop from the plot of equipotential lines which are perpendicular to the flow lines. A long distance from the wellbore, perpendicular to the flow lines. A long distance from the wellbore, the flow is radial as viewed from above (plan view) and from the side view (parallel to the top and bottom of the bed). At some point nearer the wellbore flow starts to converge and become nonradial. This nonradial flow, when the flow is still parallel to the top and bottom of the bed, but is no longer parallel to the top and bottom of the bed, but is no longer radial from a plan view, is designated nonradial flow phase 1. At some position, the flow starts converging towards the perforation instead of the wellbore and the casing/cemented borehole perforation instead of the wellbore and the casing/cemented borehole becomes an obstacle. Nonradial flow phase 2 takes place when the fluid (from a side view) stops being parallel to the top and bottom of the bed. The flow from both a plan and side view is converging towards the perforation.

This paper was prepared for the Abnormal Subsurface Pressure Symposium of the Society of Petroleum Engineers of AIME, to be held in Baton Route, La., May 15–16, 1972. Permission to copy is restricted to an abstract of not more than 300 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 OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, 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 Gas reservoir performance data were generated numerically to study the magnitude of three energy sources in abnormal pressured reservoirs. It was found that pressured reservoirs. It was found that peripherial water influx and formation peripherial water influx and formation expansion made the greatest long-term energy contribution. Based on the generated data, a technique is presented for determination of gas-in-place. Attempts were made to apply the technique to conventional field data with inconsistent success. Introduction The petroleum industry has become indoctrinated into evaluating all gas reservoirs based on the P/Z - Gp Plot. This indoctrination has been so complete that gas reservoirs that deviates from a straight line indicates water-influx or gas-efflux. During the entire period of indoctrination, it has been known that very restrictive assumptions were made in order to justify the P/Z - Gp straight line relationship. These assumptions are:No loss or gain of energy from outside forces;The connate water does not expand;The pore space does not contract;The gas is always single phase in the reservoir; andThe pressure used in the equation represents the volumetric average reservoir pressure. In many field examples these limitations placed little restriction on the accuracy of the P/Z - Gp plot. With the advent of low permeability, high condensate, high rock compressibilities, or limited water influx the P/Z - G curve began to yield apparently correct, but unfortunately erroneous answers in the early life of a gas reservoir. This divergence from the norm has resulted in considerable re-evaluation of existing techniques of gas reservoir analysis. This re-evaluation has been most noticeable in the area of abnormal pressured gas reservoirs. Three major areas of divergence from the P/Z - Gp plot have received major emphasis:Greater than normal formation compaction.

Laboratory investigations have been made to study the effect of variations in fluid characteristics, gas saturation, water saturation, and water injection rate on oil recovery by water flooding. Three synthetic gas-saturated crude oils having bubble points of 860, 1,540 and 1,885 psi were used as reservoir fluids. Repeated tests were made in which a sand pack, saturated with water and synthetic oil, was produced by solution gas drive followed by water flooding at various pressure levels. Oil recovery by solution gas drive and subsequent water injection is shown to vary with the pressure and rate at which the water flood is conducted. The pressure at which optimum flooding conditions exist is shown to be a function of the physical characteristics of the reservoir fluid. For the systems studied, increases in oil recoveries of near 10 per cent were obtained by flooding at the most desirable conditions. Variations in initial water saturations gave results similar to those in the literature. Introduction Most of the waterflooding studies investigating means of improving present exploitation processes have been conducted at low pressures with little effort to simulate reservoir conditions. Holmgren and Morsel performed a waterflooding study at 300 to 500 psi wherein the gas saturation was created by injecting gas, letting dissolved gas evolve from the oil, and then flushing the core with "live" oil until the desired gas saturation was obtained. Their results show increasing oil recoveries with increasing gas saturations. Data presented by Guerrero and Kennedy, et al, indicate that in some instances waterflooding at approximately 500 psi below the original bubble point results in a lower residual oil saturation than is obtained when water flooding above the bubble point. In their work gas saturations were created by primary depletion. By correcting low pressure flooding data for fluid shrinkage, Dyes found that a maximum oil recovery may be obtained by flooding with initial gas saturations of from 7 to 12 per cent.