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When the drainage area of a flowing well is long and narrow, the pressure transient behavior of the well often cannot be analyzed by conventional means. Well tests which appear to exhibit linear flow behavior for extended periods, beyond the length of time which could be attributed to flow to a fracture, have been observed for both geothermal wells and for oil and gas wells. In geothermal formations and in some of the deep low-permeability gas fields the elongated reservoir shape results from long parallel faults which appear to bound the formations. Typically such wells are also penetrating natural fractures. In other reservoirs the elongated drainage shape is due to the river delta or alluvial environment in which the reservoir sands were originally deposited. Using a recently developed scheme for custom type curve generation for a wide variety of flow geometries, the particular behavior of the well producing from an elongated linear flow system is presented in detail. Cases examined include fractured wells of variable fracture length in varions positions within the flow channel and also of variable length. The effects of partial penetration are also demonstrated. This paper illustrates the use of custom type curves in computer-aided type-curve matching. With the help of relatively inexpensive computer graphics, custom type curves are displayed which exactly represent whatever is known about a particular drainage geometry, including such variables as formation thickness and areal extent, fracture length, partial penetration, and well location. Familles of curves can be generated and displayed along with the data to help determine unknown features of the reservoir geometry. An important contribution included in this work was the development of a set of orthogonal dimensionless parameters which facilitate the generation of familles of type curves which vary one reservoir shape parameter with implied effects on other parameters. The dimensionless solutions for any reservoir geometry are then readily developed for use in computer-aided type curve matching. Lorsque la zone de drainage d'un puits de production est longue et étroite, les méthodes classiques d'analyse du comportement des changements de pression ne peuvent être utilisées. De tels comportements, se prolongeant après la période pouvant être attribuée à une fracture, ont été observés pour des puits produisant de l'huile, du gaz et même pour certains puits géothermiques. La géométrie allongée, que l'on rencontre parfois dans certaines formations géothermiques et poches de gaz à grande profondeur et de faible perméabilité, peut être expliquée par des réseaux de fractures parallèles qui limitent la formation. Naturellement, les puits forés dans de telles formations peuvent traverser des fractures naturelles. Pour d'autres réservoirs, la forme allongée peut être causée par la géométrie de l'environnement dépositionnel deltaïque. Utilisant une méthode récemment développée permettant de produire des courbes caractéristiques de changement de pression pour une grande variété de géométries, le comportement particulier des puits drainant des formations allongées est présenté en détail. Les cas suivants ont été analysés : fissuration avec modification de la longueur de la fracture et diverses positions du puits dans la formation avec pénétration partielle de différentes longueurs. Les courbes sont construites directement sur le terminal. Elles prennent en compte exactement ce qui est connu de la géométrie du réservoir, de l'épaisseur, la forme, la longueur de la fissure, de la longueur de la zone perforée et de la position du puits. Des familles de courbes peuvent être générées et affichées, puis comparées aux données pour déterminer les paramètres inconnus de la géométrie du réservoir. Une contribution importante, présentée dans cet article, est le développement d'un système de paramètres orthogonaux sans dimensions qui facilite la génération des courbes caractéristiques. Les courbes caractéristiques de pression, correspondant à des géométries spécifiques à l'utilisateur, peuvent être superposées aux données de pressions en vue de déterminer les paramètres inconnus du réservoir (type curve matching).

Experience shows that high-performance fractures (HPFs) may retain near-unit-flow efficiency (equivalent to zero skin in a vertical well) and rarely fail, even in highly deviated wells. This may be partly because overly simplistic models of the well flow behavior lead operators to maintain wells at lower production rates than could have been achieved for the same amount of injected proppant with a vertical-well-completion design. Rigorous models that account for widely accepted rock-mechanics fundamentals indicate that the fracture-to-well connection is compromised in deviated wells and lead to questions concerning whether the bulk of the flow to the well actually passes through the fracture. Distributed volumetric sources are used in this model to rigorously model a wide variety of possible fracture geometries such as an expanded wellbore because of halo effect, flow strictly through the fracture, and combined flow through a single fracture and to remaining flowing perforations not connected to the fracture. The model also includes turbulent-flow effects that may occur for radial-flow conditions in the fracture plane or in the reservoir opposite wellbore sections not connected to the fracture, along with high-velocity flow through the perforation tunnels. It also computes the effective flow area at the resulting face between the reservoir and the completion to check whether flow velocity exceeds conditions that would risk production of reservoir fines, and it estimates the screen-flow velocity on the basis of the number of flowing perforations. This comprehensive view of the HPF completion enables a thorough analysis of the risks of flowing the well at high rate. Field examples show that the new model depicts real field conditions in calculating the total skin, flow fractions, and the flux for HPF completions in high-rate gas and oil wells. Complete inflow-performance behavior for likely flow patterns for HPF wells in oil and gas reservoirs is provided. [ABSTRACT FROM AUTHOR]

In this work, we present an industrial automation framework for control and optimization of hydrocarbon-producing fields while satisfying business and physical constraints. The all-encompassing reservoir-management problem is decomposed into a hierarchy of decision-making problems at different time scales. We exemplify the proposed approach through a case study on a multiple-layer reservoir with a classical waterflood problem, in which a numerical reservoir model is used as a virtual field. A model-predictive control (MPC) strategy is used to regulate well and field instrumentation at economically optimal set points determined by an overlying supervisory control level. The study demonstrates significant reduction in water-handling costs and increased oil recovery. This work is a starting point for further development in automatic intelligent reservoir technologies, which capitalize on the abilities of permanent instrumented wells and remotely activated downhole completions. [ABSTRACT FROM AUTHOR]