We describe the development of a knowledge-based system to predict relative permeabilities to describe the flow of fluids in oil, gas or condensate reservoirs. The software applies heuristic knowledge and artificial intelligence techniques to identify the appropriate experimental methods for measuring the relative permeabilities, and to decide on the relevant mathematical models and computational steps to simulate the experiments. The selected models and computational steps are used together with the built-in database to generate the relative permeability data. Rules that relate the combination of field development scenario, fluid PVT properties, rock lithology and petrophysical properties are included in the knowledge base. The basis of the software is that, in some instances, precisely defined rules based on quality published data and our expertise can do better than deterministic and purely statistical methods. This view is especially true in areas with limited and/or poor-quality data, as currently exists in gas/condensate and gas/water relative permeability predictions. The paper describes the software design approach, philosophy and architecture. The mathematical and heuristic models used to generate the relative permeability data are briefly described. The target applications of the software are as follows:Tool to generate relative permeability and capillary pressure data for input to numerical simulators and material balance calculations;Tool to perform a series of "what if' calculations to determine the effects of lithology, fluids saturations and PVT properties, interfacial tension and velocity on endpoint saturations and relative permeability functions;Tool to analyse/interpret laboratory coreflood data;Tool to generate relative permeability data when coreflood data is not available or is incomplete (e.g. when only endpoint data are available); andTool for use by the reservoir engineer to design a special core analysis program for a new field or study. Introduction Relative permeability is used to describe multiphase flow in a porous medium. Such data are important input to many reservoir engineering calculations, providing a basic description of the way in which the phases will move in the reservoir. Definition of the flow process can have a significant effect on the predicted hydrocarbon production rate and duration and is important in calculating the volume of recoverable hydrocarbon reserves. The predicted production rates, the plateau level and duration, plus the expected water cut will all influence development plans. The number of wells, the balance between injectors and producers, the sizing of separation equipment, and design of facilities in general can all be impacted upon by the multiphase flow properties of the reservoir. Ultimately, together with many other inputs, relative permeability assists in determining reservoir economics, and hence guiding investment decisions. Although ways to determine relative permeability from measurements made in the field have been proposed, they are fraught with problems and have never been regularly used. The most common method for determining relative permeability has been laboratory special core analysis. Laboratory measurement of representative relative permeability data on a reservoir core-fluid system is a complex task. The experiments are costly, typically more than $100,000 each, and time consuming, often taking up to six months to complete. P. 219

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A design of chokes in series has been carried out in order to minimize sand erosion in choke boxes and beams. A multiphase flow simulation program was developed to determine the size of the choke orifices and the sequence of installation. Previous field experience determined beneficial effect of using chokes coated in their internal area from end to end with tungsten carbide. Failures in choke boxes and beams have been occurring in about 59 out of the 222 production strings in the North of Monagas area in Venezuela to the present time. In fact, 139 failures due to sand erosion occurred during 1996 causing repair costs of about $339000. The installation of a design consisting of chokes in series at the well head, drastically minimizes sand erosion, reducing production losses, oil leaks, maintenance costs and unsafe operations. The multiphase flow simulation program based design resulted in the installation of three chokes in series protecting them from sand erosion in the two wells evaluated. During five (5) months, the pre-established period of time for analysis, well No. 1 kept producing continuously. Visual inspection confirmed that no sand erosion had occurred in any of the chokes. Introduction High gas and oil rates associated to sand production with high well head pressures passing through one choke box with conventional material usually causes erosion of the beam and its choke box; the severity of the erosion process may deteriorate them completely, giving place to leaks. Sand production erodes the internal parts of a well head including wing valves, tees, subsurface safety valves, choke boxes and beams affecting the well safety system and production operations. These accessories are inspected periodically, and frequently, they have to be repaired or replaced. This type of failure causes deferred production and dedication of production crews to correct erosion problems affecting operational costs. Research has been carried out on the erosive processes in materials with and without the presence of sand. In the oil industry, an API formula has been developed to predict the limit velocity for flow of fluids, above which an erosive process, in non corrosive environments and without the presence of solid particles, can be initiated. Deffenbaugh showed results on the erosion velocity for carbon steels excluding its application for flow restrictions as chokes. Likewise, Deffenbaugh proposed a formula to predict erosion velocity in the presence of sand. Sontvedt reported the limit velocities for erosion for carbon steels in the absence of corrosive fluids based upon studies of materials for chokes, and also for other special materials resistant to erosion. P. 987^

A knowledge-based system has been developed which predicts relative permeabilities to describe the flow of fluids in oil, gas or condensate reservoirs. The software applies heuristic knowledge and artificial intelligence techniques to identify the appropriate experimental methods for measuring the relative permeabilities, and to decide on the mathematical models and computational steps to use to generate the data. The selected models and computational steps are used together with the inbuilt database to generate the relative permeability data which honour the physics of the flow system. Rules that relate the combination of field development scenario, fluid PVT properties, rock lithology and petrophysical properties are included in the knowledge base. The paper describes the parts of the software which address the complex problems associated with relative permeability predictions in gas condensate reservoirs undergoing pressure depletion. The current version of the software runs on a PC under the Microsoft Windows operating system and exploits fully the graphical user interface for data input and output. Introduction The increasing emphasis on optimising recovery from gas condensate fields and the extensive development and use of reservoir simulators for predicting reservoir performance are together creating a widespread need for reliable basic data on rock flow behaviour. In general, in reservoir study involving two phase flow, the relative permeability is the parameter with the major control on reservoir performance. Relative permeabilities provide a basic description of the way in which the phases will move in the reservoir. Definition of the flow process can have a significant effect on the predicted gas/oil production rate and duration, and is important in calculating the volume of recoverable hydrocarbon reserves. The predicted production rates, the plateau level and duration, plus the expected water cut will all influence development plans. The number of wells, the balance between injectors and producers, the sizing of separation equipment, and design of facilities in general can all be impacted upon by the multiphase flow properties of the reservoir in the near wellbore region. Ultimately, together with many other inputs, relative permeability assists in determining reservoir economics, and hence guiding investment decisions. Laboratory measurement of representative relative permeability data on a reservoir core-fluid system is a complex task. The experiments are costly, typically more than $100,000 each, and time consuming, often taking up to six months to complete. Accuracy is limited to the specific core samples and is bounded by narrow saturation limits. A fundamental theoretical approach to modelling multiphase fluid flow in porous rocks is prevented by the complex nature of the problem. Major difficulties arise in mathematically describing flow through a porous system where the lengths, diameters and connectivity of channels are largely unquantifiable. For gas condensate systems the issue is complicated further as the thermodynamic behaviour of a multicomponent system close to their critical region needs to be taken into account. As a result, the experimentally determined gas condensate relative permeabilities are few and usually present a wide range of scattering. Consequently, it is very difficult to determine a representative average function on any basis, with a reservoir unit basis being the most difficult. P. 637