The paper describes the upscaling and reservoir simulation of a giant Middle East oil field, the geological modeling of which is described in a companion paper. 1 The main objective of the study was the simulation of the irregular water advance observed in some parts of the field as a consequence of peripheral water injection.Three scales of heterogeneity were identified in the characterization phase: the matrix, the stratiform Super-K intervals, and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used.The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled with algebraic methods, while the stratiform Super-K layers and fracture properties were reproduced explicitly at the simulation gridblock scale through an original upscaling procedure.The history match was achieved in a short time by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification.Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order.In a later stage, the model was used to run production forecasts under different exploitation scenarios.The conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, is necessary for accurate reservoir simulation and effective reservoir management.

Summary There have been many different approaches to quantifying cutoffs, with no single method emerging as the definitive basis for delineating net pay. Yet each of these approaches yields a different reservoir model, so it is imperative that cutoffs be fit for purpose (i.e., they are compatible with the reservoir mechanism and with a systematic methodology for the evaluation of hydrocarbons in place and the estimation of ultimate hydrocarbon recovery).These different requirements are accommodated by basing the quantification of cutoffs on reservoir-specific criteria that govern the storage and flow of hydrocarbons. In so doing, particular attention is paid to the relationships between the identification of cutoffs and key elements of the contemporary systemic practice of integrated reservoir studies. The outcome is a structured approach to the use of cutoffs in the estimation of ultimate hydrocarbon recovery. The principal benefits of a properly conditioned set of petrophysical cutoffs are a more exact characterization of the reservoir with a better synergy between the static and dynamic reservoir models, so that an energy company can more fully realize the asset value. Introduction In a literal sense, cutoffs are simply limiting values. In the context of integrated reservoir studies, they become limiting values of formation parameters. Their purpose is to eliminate those rock volumes that do not contribute significantly to the reservoir evaluation product. Typically, they have been specified in terms of the physical character of a reservoir. If used properly, cutoffs allow the best possible description and characterization of a reservoir as a basis for simulation. Yet, although physical cutoffs have been used for more than 50 years, there is still no rationalized procedure for identifying and applying them. The situation is compounded by the diverse approaches to reservoir evaluation that have been taken over that period, so that even the role of cutoffs has been unclear. These matters assume an even greater poignancy in contemporary integrated reservoir studies, which are systemic rather than parallel or sequential in nature, so that all components of the evaluation process are interlinked and, therefore, the execution of anyone of these tasks has ramifications for the others (Fig. 1). A particular aspect of the systemic approach is the provision for iteration as the reservoir knowledge-base advances. For example, simulation may be used in development studies to identify the most appropriate reservoir-depletion mechanism, but, once the development plan has been formulated, the dynamic model is retuned and progressively updated as development gets under way. The principal use of cutoffs is to delineate net pay, which can be described broadly as the summation of those depth intervals through which hydrocarbons are (economically) producible. In the context of integrated reservoir studies, net pay has an important role to play both directly and through a net-to-gross pay ratio. Net pay demarcates those intervals around a well that are the focus of the reservoir study. It defines an effective thickness that is pertinent to the identification of hydrocarbon flow units, that identifies target intervals for well completions and stimulation programs, and that is needed to estimate permeability through the analysis of well-test data. The net-to-gross pay ratio is input directly to volumetric computations of hydrocarbons in place and thence to "static" estimates of ultimate hydrocarbon recovery; it is a key indicator of hydrocarbon connectivity, and it contributes to the initializing of a reservoir simulator and thence to "dynamic" estimates of ultimate hydrocarbon recovery.

This paper describes a technique to incorporate conductive faults and -fractures in a reservoir simulation model. The technique is appropriate for reservoirs with significant primary matrix productivity, and a large spacing between fractures (in the order of tens of meters). The single porosity (one grid) formulation is applied. Any fracture geometry can be represented accurately without grid modifications. The key elements of the approach are pseudo relative permeability curves for grid bocks containing fractures. These curves are determined through an analytical procedure, based on the local fracture and matrix properties. The method is applied successfully to a Middle East carbonate reservoir. Introduction Conductive faults and -fractures are common features in reservoirs worldwide. Several methods have been proposed to model fluid flow in fractured reservoirs. Well known is the Warren and Root [1] approach, which applies homogenization of the fracture properties and a dual porosity formulation (separate matrix and fracture grids). The homogenization of the fracture properties is possible when the Representative Elementary Volume (REV) [2] of the fracture network is smaller than the reservoir simulation grid. This paper focuses on fracture patterns that can not be homogenized, because the fracture REV is several times larger that the grid block size. Figure 1 provides an illustration. This figure represents a 10 by 22 kilometer sector of a much larger carbonate reservoir. The displayed fracture pattern is obtained from fracture analysis [3]. It is superimposed on a 250 by 250 meter simulation grid. In this example the conductive fractures are identified as the key contributor to unstable movement of the water injection front. Consequently, the fracture pattern must be incorporated when a simulation model is to be built. Several methods are available in the literature to integrate conductive fractures in a reservoir simulation model. Some of these methods are described below, with their strengths and weaknesses summarized in Table 1. Phelps et al [4] apply local grid refinement (LGR) to model conductive fractures explicitly. This approach is thorough in the handling of the physical elements of the displacement process. However, numerical difficulties may be experienced due to a large flow rate in grid blocks with a small pore volume. This is especially the case when a rapidly advancing water tongues develop due to gravity segregation in the fractures. Henn et al [5] extend the LGR technique by applying vertical lumping of the fractured grid blocks, in combination with an analytical treatment of capillary/gravity equilibrium in the fracture. Their method strongly improves numerical performance of the simulation model. The general disadvantage of these LGR approaches is that they are impractical for complex fracture patterns like the one shown in Figure 1. Cosentino et al [6] apply a dual media (dual permeability dual porosity) formulation to model conductive fractures explicitly. Their approach facilitates the capture of any complex fracture geometry without the need for modifications to the grid geometry. The method is thorough in its treatment of the processes that may take place during water flooding. The numerical challenges, with respect to high flow rates in grid cells with a small pore volume, are comparable to those experienced in the conventional LGR approach. Subsequently, relatively small time steps are required to adhere to stability criteria.

There have been many different approaches to quantifying cut-offs, with no single method emerging as the definitive basis for delineating net pay. Yet, each of these approaches yields a different reservoir model, so it is imperative that cut-offs be fit-for-purpose, i.e. they are compatible with the reservoir mechanism and with a systematic methodology for the evaluation of hydrocarbons in place and for the estimation of reserves. These different requirements are accommodated by basing the quantification of cut-offs on reservoir-specific criteria that govern the storage and flow of hydrocarbons. In so doing, particular attention is paid to the relationships between the identification of cut-offs and key elements of the contemporary systemic practice of integrated reservoir studies. The outcome is a structured approach to the use of cut-offs in the estimation of reserves. The principal benefits of a properly conditioned set of petrophysical cut-offs are a more exact characterization of the reservoir with a better synergy between the static and dynamic reservoir models, so that an energy company can more fully realize the asset value. Introduction In a literal sense, cut-offs are simply limiting values. In the context of integrated reservoir studies they become limiting values of formation parameters. Their purpose is to eliminate those rock volumes that do not contribute significantly to the reservoir evaluation product. They have typically been specified in terms of the physical character of a reservoir. If used properly, cut-offs allow the best possible description and characterization of a reservoir as a basis for simulation. Yet, although physical cut-offs have been used for over 50 years, there is still no rationalized procedure for identifying and applying them. The situation is compounded by the diverse approaches to reservoir evaluation that have been taken over that period, so that even the role of cut-offs has been unclear. These matters assume an even greater poignancy in contemporary integrated reservoir studies, which are systemic rather than parallel or sequential in nature, so that all components of the evaluation process are interlinked and therefore the execution of any one of these tasks has ramifications for the others (Fig. 1). The principal use of cut-offs is to delineate net pay, which can be broadly described as the summation of those depth intervals through which hydrocarbons are (economically) producible. In the context of integrated reservoir studies, net pay has an important role to play both directly and through a net-to-gross pay ratio. Net pay demarcates those intervals that are the focus of the reservoir study. It defines an effective flow thickness that is pertinent to the identification of flow units, that identifies target intervals for well completions and stimulation programs, and that is needed to estimate permeability through the analysis of well test data. The net-to-gross pay ratio is input directly to volumetric computations of hydrocarbons in place and thence to "static" estimates of reserves, it is a key indicator of hydrocarbon connectivity, and it contributes to the initializing of a reservoir simulator and thence to "dynamic" estimates of reserves. Unfortunately, there is no universal definition of net pay nor is there general agreement on how it should be delineated. For this reason, net pay has been incorporated within integrated reservoir studies in many different ways that have not always been fit for purpose. In particular, there is no generally accepted method for quantifying net pay cut-offs, without which net pay cannot be delineated. In an attempt to redress some of these shortcomings, this paper is directed at building a systematic foundation for the definition and role of cut-offs in integrated reservoir studies. It tracks the origins of physical cut-offs from both geoscience and engineering perspectives in both Western and Eastern hemispheres. It outlines what they are and why we need them, describes how they should be quantified, and proposes a structured method for incorporating them within integrated reservoir studies for the evaluation of hydrocarbons-in-place and the estimation of reserves. The starting point is some basic terminology.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe paper describes the upscaling and reservoir simulation of a giant Middle East oilfield, whose geological modeling is described in a companion paper (1). The main objective of the study was the simulation of the irregular water advance observed in some parts of the field, as a consequence of peripheral water injection.Three scales of heterogeneity were identified in the characterization phase, namely the matrix, the stratiform Super-K intervals and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used.The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled using algebraic methods, while the stratiform Super-K layers and fractures properties were explicitly reproduced at the simulation gridblock scale, through an original upscaling procedure.The history match was achieved in a short time, by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification.Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order.In a later stage, the model was utilized to run production forecasts under different exploitation scenarios.Conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, are necessary requisites for accurate reservoir simulation and effective reservoir management.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes a method to condition facies (rock-type) permeabilities in geostatistical models to dynamic reservoir data: the flow meter log and the well test KH value. The proposed approach consists of two steps. In the first step, the flow meter logs are transformed into (reference) permeability profiles by use of the well test permeability-thickness (KH). This transformation is analytical, meaning that a geostatistical reservoir realization and numerical flow simulation are not required. In the second step, synthetic permeability profiles are computed for the known rock-type classification at the well locations. An optimization procedure is applied to improve the match of these synthetic permeability profiles with the reference (flow meter) profiles. In this process the initial (core based) rock-type permeability model is modified. The optimization procedure simultaneously takes into account all the wells, and is subject to geological constraints imposed by the user (ranking, permeability bounds). Although a number of assumptions must be verified, this fully analytical approach leads to a fast, flexible, and practical optimization routine that is relatively easy to implement. The up-front integration of dynamic data into the modeling process leads to a more representative permeability description than is obtained using only plug values. Because of the global nature of the optimization method, a satisfactory match can be extrapolated throughout the reservoir with a reasonable degree of confidence. The paper presents a successful application of the procedure to a Middle East reservoir.

Recent development of Bachaquero 2 Field (Lake Maracaibo, Venezuela) has been based mainly on cyclic steam injection on horizontal wells. Initial oil deliverability of the heated wells proved to be up to 5 times greater with respect to the cold wells. This paper presents the results of a multi-disciplinary project focussed on the drilling of a pair of horizontal wells for cyclic stearn injection. The project involved a reservoir characterization and a numerical simulation phase, the drilling, steam injection and production of these wells, a data acquisition project and eventually a fial detailed simulation stage. Experimental and numerical results show that the presence and the thickness of interbedded shale has a severe impact on heat distribution. Very little interference has to be expected between parallel horizontal wells when the separating shale is continuous and its average thickness is greater than about 12 feet. A preliminary stochastic description of the reservoir can be very useful in assessing the presence and expected average thickness of the interbedded shale. The experience allowed us to set the best production strategy for the 2-horizontal well system, in terms of sequence and duration of the cycles, steam rate, total injected steam, steam quality and soak time. It also helped in setting guidelines for the future development of the Bachaquero 2 Field. P. 293

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Oficina Formation, Eastern Venezuela, contains large amounts of gas reserves, which are strategic for the energetic policy of the country. In the Zapatos-Mata R field, these reserves are stored in a thick transgressive sequence of deltaic channels and shore bars (over 3000 ft), as rich gas condensate accumulations of various importance, from few to hundreds of Bcf. Over 400 wells have been drilled in the area since the 1950's, which in general have been selectively completed in progressively shallower intervals. Gas injection has been implemented in most of the main reservoirs since the early 1960's.An integrated reservoir study was started during year 2000, with the aim of establishing a new exploitation strategy by means of a simulation model. However, early in the project, it became obvious that a straight full field simulation would have been a prohibitive task, given the complexity of the geology, the variation in the fluid type and properties, and the number of wells, completed intervals and reservoirs (almost 700 official reservoirs were reported in the study area). Still, the availability of a full field model was deemed critical to establish a representative exploitation plan in the prediction phase, especially because a commingled production option is being considered.An original procedure was therefore defined, based on a stepwise approach. In a preliminary stage, simulation studies were carried out individually for the most important reservoirs. The modeling was performed using a full compositional formulation. Several of these models were built and partially history matched.In a later stage, these individual models were lumped together in a progressive mode, while checking the quality of the history match. This process eventually led to the building of a full field model, including all the most important reservoirs and over 80% of the total reserves of the area. This model has about 65 layers and more than 300,000 active cells.Conclusions of the study showed that this stepwise approach is an interesting option for the full scale simulation of giant multilayer gas condensate reservoirs, since it allows for the decoupling of the problems related to the model building and history match issues, which are faced and solved early in the simulation process. Moreover, individual models can be used for investigating the behavior of the single reservoirs, as well as for special tasks like well performance analysis and sensitivities studies.