Liquid-vapor equilibria for the binary systems methaneethane, methane-carbon dioxide, and ethane-carbon dioxide and for the ternary system of methane-ethanecarbon dioxide were measured at 250.00K and at pressures of 13-80 atm. Additional liquid-vapor measurements are reported for methane-carbon dioxide at 230.00 and 270.00K.The increased emphasis of recent years in the low-temper-, ature processing of natural gas has resulted in the need for the phase equilibrium properties of light hydrocarbon-carbon dioxide systems. Some experimental data are available for the binary systems composed of methane, ethane, and carbon dioxide, but no measurements have been made on the ternary system. Thus, the work reported here will be of considerable value to both the thermodynamicist and the process design engineer. Previous Experimental WorkExperimental phase equilibrium measurements for the binary systems methane-ethane, methane-carbon dioxide, and ethane-carbon dioxide prior to 1973 have been listed in a recent review paper (S). Table I summarizes all the recent work not reported in ref. 9. There are no experimental data available for the ternary system.

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Reservoir management engineers at Aramco are fortunate to have a wealth of information about their reservoirs in the corporate database. However, this wealth of information comes with a challenge of analyzing this immense collection of data and utilizing this information for decision-making. In this study we used data mining process to explore our database and evaluate the performance of wells in a study area of Ghawar field. The performance of more than 450 wells was then related to the super-k existence from flowmeter data. The existence of super-k layer was believed to cause premature water breakthrough and hence poor vertical sweep. The objective of the study was to answer the following question: Will producing a super-k well without isolating the super-k layer result in less cumulative oil production after water breakthrough? In this paper we developed a methodology to identify and quantify super-k while avoiding the pitfall of black or white (i.e. super-k or non super-k well). Super-k quantification was accomplished by deriving Fluid Flow Index from flowmeter surveys. The next challenge was to come up with a consistence measure of well performance so that all the wells can be compared on the same basis. This challenge was overcome by introducing the new definition of cumulative oil production and average oil rate after water breakthrough. In this paper we developed correlations to predict the performance of future wells to be drilled in the area. The study indicated that there was a positive correlation between super-k and high average rate after water breakthrough. Also, it was found that anomalous flood front encroachment in the east flank of the field is unrelated to the super-k. The study showed that reservoir performance is controlled by the interaction between Faults/ Fractures and Super-k layers. The results of this study created a paradigm shift in perceiving super-k layers in Ghawar. Field data showed an improved well performance by perforating isolated super-k layers. Moreover, the derived Fluid Flow index was used in building an enhanced and more realistic model for the field. Introduction Super-K or extremely permeable intervals are quite common in the study area of Ghawar field. In this carbonate reservoir, super-k zones can be horizontal layers, created during deposition or after digenesis, or they are just as likely to be sub-vertical fractures and faults1. However, since most of the wells in the study area are vertical, the probability of intersecting sub-vertical fractures and faults is very low. The first approach to treating super-k zones in carbonate reservoirs is to identify the nature of these zones in the wellbore. To this end, flowmeter logs is required to first identify potential zones and second characterize their properties. Continuous flow meters are routinely obtained in wells with openhole completions in Ghawar field to improve sweep from all the zones. It became apparent that in some wells, extremely high fluid-flow was confined to thin, apparently strati-bound ‘super-permeable’ intervals. This is in marked contrast with other wells, where continuous flow meters indicated that the fluid flow was distributed more uniformly across the openhole reservoir section.

A dynamic simulation model containing several million cells shows geological details used to simulate the vertical fractures and high stratiform permeability of the Ghawar field. Observed performance data have shown that well intersections in the Ghawar field exhibit thin intervals of extremely high productivity. These can be related to high-permeability layers (stratiform features) or to subvertical faults and fractures. To capture observed field behavior in a dynamic simulation model, these two features must be incorporated in the simulation model. This paper discusses how vertical fractures and high stratiform permeability were simulated in the world's largest oil reservoir. Introduction It has long been known that well intersections in the Ghawar field show thin intervals of extremely high productivity. These can be related to high-permeability layers (stratiform features) or to subvertical faults and fractures. This paper discusses the characterization of these features and their inclusion in a field-scale simulation model. All high-permeability features (both matrix-and fracturerelated) are incorporated into the "fracture" component of a dualporosity, dual-permeability (DPDP) simulation. Fine-grid modeling is used to validate the approach and to gain an understanding of the physical processes taking place within the reservoir. Practical considerations and difficulties encountered in setting up a large-scale (16×17 km) sector model using the DPDP properties are discussed. Results for several runs that include 40 years of production history show that the methodology has the potential to improve the simulation modeling of this field. BackgroundThe Ghawar field is the largest oil field in the world, stretching some 230 km in length and 25 km in width. The reservoir is located in the typically highly porous and permeable carbonates of the Arab-D formation. The reservoir has been under waterflood for almost 40 years. Attempts to history match the field with singleporosity models have had difficulty in matching the speed of water breakthrough and reproducing the irregular nature of the flood front. With the addition of horizontal wells and the use of borehole image logs, the identification and measurement of fractures in wellbores has added to the understanding of the Ghawar field.

SPE Member Abstract This paper demonstrates a technique of using log data coupled with lithology dependent porosity-permeability transforms to calculate facies-dependent Leverett J-functions for the Hadriya reservoir. A comparison of initial water saturation profiles from formation analysis logs versus profiles from a single global J-function and facies-specific J-functions are presented. These facies dependent J-functions were then used to compute facies specific imbibition and drainage relative permeabilities for both the wetting and non-wetting phase. Introduction One of the most important aspects of constructing 3-D simulation models is to accurately describe the distribution of fluids at the beginning of history. Since the fluid contacts were known, the next step was to determine the vertical distribution of water above the OOWC. One of the best methods of determining water saturations is the use of capillary pressures. The Hadriya reservoir exhibits a large degree of heterogenity, and thus the capillary properties varied considerably throughout the reservoir, depending on the permeability, porosity, clay content and pore size. Comprehensive descriptions of capillary pressure data at each well location would have required an extensive and costly coring and testing program. Therefore, to correlate and interpolate capillary pressure data for the Hadriya reservoir it was decided to develop J-function values. Development of a global J-function was possible using core data, however, since the Hadriya reservoir has 19 facies there was insufficient core data to accurately describe a J-function for each facies. Some facies had little or no data from core analysis. A search for data led to the use of FALs (formation analysis logs). P. 525^