An experimental study on the system hydrogen sulfide‐carbon dioxide was performed from the critical region to the solid‐liquid‐vapor region. For seven mixtures individual phase diagrams were determined by the establishment of dew, volume percentage liquid, hubble, critical, and triple points. A splendid study of this system had been reported earlier by Bierlein and Kay (1) for temperatures above 32°F. However from a temperature point of view this earlier work represents about one half of the phase diagram from the critical locus to the locus of triple points. Hence in this study particular attention was devoted to the lower temperature regions. Equilibrium constants were determined from 100 to 1,200 lb./sq. in. abs. Vapor and liquid equilibrium compositions from this investigation were compared with those obtained by Bierlein and Kay (1) at 20, 40, 60, and 80 atm. Solid‐liquid‐vapor loci were found to meet at a minimum temperature, lower than either of the individual pure component triple points, due to the formation of a eutectic mixture consisting of 12.5 mole % carbon dioxide. Vapor and liquid compositions in equilibrium with solid were established along the vapor‐liquid‐solid carbon dioxide and vapor‐liquid‐solid hydrogen sulfide loci.

This paper presents a correlation for predicting the behavior of a water cone as it builds from the static water-oil contact to breakthrough conditions. The correlation is partly empirical and involves dimensionless groups of reservoir and fluid properties and of production and well characteristics. The groups were deduced from the scaling criteria for the immiscible displacement of oil by water. The correlation is based on a limited amount of experimental data from a laboratory, sand-packed model and on results from a computer program for a two-dimensional, incompressible system. Because the correlating groups are dimensionless, they can be used to estimate the performance of water coning cases not specifically considered in the correlation. However, despite its dimensionless nature, the correlation is no completely general and will not provide meaningful estimates of cone behavior in many situations. INTRODUCTION AND BACKGROUND The production of water from oil wells is a common occurrence which increases the cost of producing operations and may reduce the efficiency of the depletion mechanism and the recovery of reserves. We will deal with one cause of this water production, namely, coning. The coning of water into a producing well is caused by pressure gradients established around the wellbore by the production of fluids from the well. These pressure gradients can raise the water-oil contact near the well where gradients are most severe. Gravity forces that arise from fluid density differences counterbalance the flowing pressure gradients and tend to keep the water out of the oil zone. Therefore, at any given time, there is a balance between gravitational and viscous forces at points on and away from the completion interval. When the dynamic forces at the wellbore exceed gravitational forces, a cone of water will ultimately break into the well to produce water along with the oil. We can expand on this basic visualization of coning by introducing the concepts of stable cone, unstable cone and critical production rate. For instance, if a well is produced at a constant rate and the pressure gradients in the drainage system have become constant, a steady-state condition is reached. If, at this condition, the dynamic forces at the well are less than the gravity forces, then the water or gas cone that has formed will not extend to the well. Moreover, the cone will neither advance nor recede, thus establishing what is known as a stable cone. Conversely, if the pressure in the system is in an unsteady-state condition, then an unstable cone will continue to advance until steady-state conditions prevail. If the flowing pressure drop at the well is sufficient to overcome the gravity forces, the unstable cone will grow and ultimately break into the well. It is important to note that in a realistic sense, stable cones may only be "pseudostable" because the drainage system and pressure distribution generally change. For example, with reservoir depletion, the water-oil contact may advance toward the completion interval, thereby increasing chances for coning. As another example, reduced productivity due to well damage requires a corresponding increase in the flowing pressure drop to maintain a given production rate. This increase in pressure drop may force an other-wise stable cone into a well. The critical production rate, well known in the literature, is the rate above which the flowing pressure gradient at the well causes water (or gas) to cone into the well. It is, therefore, the maximum rate of oil production without concurrent production of the displacing phase by coning. At the critical rate, a built-up cone is stable but is at a position of incipient breakthrough. Numerous papers have been published on critical rates. Some of the better known of these include the work ofMuskat and Wyckoff, who first dealt with the coning problem;Chancy, et al, who developed expressions similar to those of Muskat but who presented results in a convenient-to-use graphical form (the "Sun" method); andMeyer and Garder, whose analysis is based on radial-flow formulas. One assumption in critical production rate analyses is that the cone has built-up to just before its breakthrough into the well. But, these analyses reveal nothing directly about the time it takes for the cone to build up to this incipient breakthrough position. Thus, water-free oil can be produced from a well for prolonged periods at rates above the critical rate before the well reaches the condition to which the critical rate applies. The published literature contains little on the rate of growth of a cone. Experimentally, Meyer and Searcy studied the rate of rise of a cone in a Hele-Shaw model. Additional related work on water breakthrough and produced water-oil ratios in water driven reservoirs was reported by Muskat, Hutchinson and Kemp, Henley, et al, and Stevens, et al. Theoretically. the basic coning equations for a water-oil system can be developed by applying the conservation of mass to each of the phases, relating flow velocities with pressure by Darcy's law, and relating pressures across water-oil interfaces by capillary pressure. With the usual boundaries at the well and reservoir limits, the solution of the resulting equations for the time behavior of a water-oil interface constitutes a free-surface, boundary-value problem. JPT P. 594ˆ

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Summary This paper describes the use of a black-oil thermal simulator to evaluate the performance of an ongoing steamflood at the Georgsdorf reservoir in the Federal Republic of Germany. An areal model was developed to represent about 1.2 × 10(6) m2 [300 acres] of the steam flood and the adjoining area where wells are located on irregular spacing. Ten years' historical performance, including six years' steam injection, were history matched to calibrate the model. The calibrated model then was used to study the future depletion of the reservoir under several options. This information was used by Gewerkschaften Brigitta und Elwerath Betriebsfuhrungs GmbH (BEB), the operator, to help make decisions about the future operation of the steam flood. Introduction Reservoir engineering was defined by Moore as the "artof developing and producing oil and gas fields in such a way as to obtain a high economic recovery." In practicing this art, the repeated objectivity of reservoir simulation can avoid the subjective distortion of analytical procedures. However, the art becomes increasingly abstract when simulation is applied to reservoir processes involving nonisothermal operations and other complex phenomena. This paper is concerned with the use of a thermal reservoir simulator to assess the historical performance of anon going steam flood at the Georgsdorf field so that possible future operating options can be evaluated. Such information can assist management in decidinghow much steam is required in certain areas,how the steam flood might be expanded, andwhere new injection wells and infill producers might be located. No analytical procedures exist to evaluate the displacement of oil by steam and water adequately in a complex geological setting where wells are drilled on irregular spacing. Thermal reservoir simulation provides this capability, but applications of such simulators can be impractical to justify, especially for smaller projects. The literature is replete with information about simulating conventional fluid displacement in isothermal systems. Substantially less is available for simulating on isothermal, chemical, and miscible processes. Coats cited much of the pertinent simulation technology and put this information into perspective in his 1982state-of-the-art paper. There is little published information on specific applications of thermal simulation. Chu and Trimble used a three-dimensional (3D), three-phasenumerical simulator in the black-oil mode to history match5 1/2 years' performance for a steam stimulation pattern in the Kern River field, CA. The model subsequently was used to optimize operating parameters. Gomaa et al. also used a black-oil thermal simulator to model elements of an inverted five-spot pattern to determine the relative importance of various steam flood and reservoir parameters for the Monarch sand in the Midway-Sunset field, CA. Munoz simulated steam flooding in the Tia Juana M-6Project, Venezuela. In this work, a 3D model was prepared for an element of symmetry in a regular inverted seven-spot. These studies addressed the effects of permeability variations, gravity segregation, and positions of completion intervals. Williams prepared a 3D model with which he determined the response to production by steam stimulation and steam displacement in the steeply dipping North Midway field, CA. Another 3D study of a steeply dipping reservoir was reported by Moughamian et al. This work provided information used to design a steam flood in the heavy-oil bearing Webster sand sequence in the Midway-Sunset field. All the studies mentioned treated a representative segment or an element of a repeated pattern where either steam stimulation or steam displacement was contemplated. All the studies provided important ideas about simulation methodology but none dealt with fieldwide simulation of ongoing steam floods with irregularly spaced wells. The Georgsdorf Field Lillie and Springer discussed the technical and economic aspects of a steam flood in the Georgsdorf field. Somepertinent reservoir description information from this paperis repeated for convenience. The Georgsdorf field was discovered in 1943 and developed largely between 1946 and 1963 by the drilling of about 350 wells. BEB operates the field for aconsortium of companies that includes itself, C. Deilmann A.G., Preussag A.G., and Wintershall A.G. Each company owns 25% of the field. The Valanginian sandstone of lower Cretaceous age is a good quality reservoir throughout much of Georgsdorf. JPT P. 1952^

There are several operations in the production of petroleum in which three-phase concurrent flow of fluids takes place. In some cases this type of flow necessarily must occur, such as the lifting and transportation of gas, crude oil, or condensate and water from the reservoir to the first separator in the field. In another operation, three-phase flow is encountered when glycol is injected into a pipeline at the well-head with oil and wet gas, in order to prevent freeze ups from gas-hydrate formation. The design of piping for vertical, horizontal, and inclined multiphase flow has been done largely by the expensive route of trial and error. Poettman, et al., have analyzed data on a number of wells flowing oil, gas, and water vertically. This laboratory study was undertaken in view of the current interest in the concurrent flow of oil and gas in field-gathering pipelines along with the injection of a third water phase such as glycol.