The simulation of fluid flow in fractured reservoirs is mostly based on the Warren-Root formulation in which the matrix is dissected into blocks by fractures(1). In modern simulators, the Warren-Root formulation has been extended to account for fluid flow in the matrix as well as in the fractures(2). These two media of contrasting transmissibility and storage capacity constitute the basis of dual porosity dual permeability modeling. Hydraulic connection between the two media is managed via a transfer function. This formulation is appropriate for cases with diffuse interconnected fractures. Alternatively, fractures can be modeled explicitly by capturing their geometries, shapes and sizes in the form of numerical grid cells. But this would be prohibitively costly in terms of run time and memory. This paper presents a method that is suitable for giant fields that are dominated by clusters of sub-vertical fractures called fracture corridors. It is based on a hybrid approach of the two alternatives mentioned. The effective Warren-Root and fracture parameters are adjusted to mimic explicit fracture modeling thereby capturing the advantages of both. The method was applied to a giant carbonate field in Saudi Arabia, which has both fracture corridors and super-permeable bodies. These bodies are typically horizontal and they inter-connect with the fracture corridors to form a combined high conductivity medium which is responsible for the unusual water movement observed in some parts of the field. The full field simulation model contains a homogeneous matrix and a fracture grid comprised of fracture corridors and super-permeable bodies. Fluid segregation is assumed in the fracture system in agreement with the physics inside conductive vertical fractures. The matrix-fracture corridor and the matrix-super permeable body exchanges are represented in a manner similar to matrix-fracture transfers in the Warren-Root dual-porosity system. Special attention was paid to matrix block size and to imbibition capillary pressure. This approach led to a reliable history match that captures the water arrival time and water production profiles in the reservoir. Introduction Fluid flow in naturally fractured reservoirs primarily takes place via high permeability and low porosity fractures surrounding matrix blocks. The simulation of such reservoirs is challenging both in terms of characterization and numerical modeling. This paper addresses some challenging aspects of numerically modeling a special kind of fractured reservoir where fractures cluster together to form the so called fracture corridors, which are also known as fracture fairways or fracture swarms. Unlike diffuse fracture networks whereby fractures are distributed within reservoir matrix rock, reservoirs with fracture corridors are not readily approximated by the Warren-Root, so-called "sugar-cube" model. This is because fracture corridors (a) are large scale features that generally cut through the reservoir thickness, (b) exist along corridors while the vast part of the reservoir may or may not be free of fractures. Such large scale but clustered fractures are akin to major faults in some ways and could be modeled explicitly by approximating them as such. At the same time, we know they actually consist of a large number of individual and relatively small high conductivity openings that are clustered and aligned together. It is possible to model such configurations by using a modified set of Warren-Root parameters. In this paper, they are in effect approximated by the judicious choice of Warren-Root parameters as in dual media modeling so as to respect the fact that they are akin to major fault lines. This approach is applied in the Arab-D full field modeling. The Arab D reservoir is carbonate and oil bearing. The model is constructed using Saudi Aramco's POWERSTM simulator and contains a total of about 9 million cells.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe simulation of fluid flow in fractured reservoirs is mostly based on the Warren-Root formulation in which the matrix is dissected into blocks by fractures (1) . In modern simulators, the Warren-Root formulation has been extended to account for fluid flow in the matrix as well as in the fractures (2) . These two media of contrasting transmissibility and storage capacity constitute the basis of dual porosity dual permeability modeling. Hydraulic connection between the two media is managed via a transfer function. This formulation is appropriate for cases with diffuse interconnected fractures. Alternatively, fractures can be modeled explicitly by capturing their geometries, shapes and sizes in the form of numerical grid cells. But this would be prohibitively costly in terms of run time and memory. This paper presents a method that is suitable for giant fields that are dominated by clusters of sub-vertical fractures called fracture corridors. It is based on a hybrid approach of the two alternatives mentioned. The effective Warren-Root and fracture parameters are adjusted to mimic explicit fracture modeling thereby capturing the advantages of both. The method was applied to a giant carbonate field in Saudi Arabia, which has both fracture corridors and super-permeable bodies. These bodies are typically horizontal and they interconnect with the fracture corridors to form a combined high conductivity medium which is responsible for the unusual water movement observed in some parts of the field. The full field simulation model contains a homogeneous matrix and a fracture grid comprised of fracture corridors and super-permeable bodies. Fluid segregation is assumed in the fracture system in agreement with the physics inside conductive vertical fractures. The matrix-fracture corridor and the matrix-super permeable body exchanges are represented in a manner similar to matrix-fracture transfers in the Warren-Root dual-porosity system. Special attention was paid to matrix block size and to imbibition capillary pressure. This approach led to a reliable history match that captures the water arrival time and water production profiles in the reservoir.
Multilateral-well technology improves well productivity by maximizing reservoir contact, resulting in field development with fewer wells and minimizing water and gas coning. The current practice of drilling long horizontal wells (up to eight km) poses the greatest technological challenge in completing the wells because of geological uncertainties, hydraulical and mechanical complications. Tremendous efforts have been made by the oil industry to meet these drilling challenges, and also in the design and completion of these types of wells. Since 2002, over 440 horizontal, multilateral and maximum reservoir contact (MRC) wells have been drilled and equipped with active Inflow Control Valves (ICV) and passive Inflow Control Devices (ICD) in Saudi Aramco. The complex architecture of those wells generally makes them more expensive to drill and complete. Therefore, their use must be justified and well planned. The planning of complex architecture wells requires thorough modeling studies to optimize total length, configure branches, place ICV and ICD along the motherbore to achieve balanced inflow along the horizontals, overcome high frictional pressure loss from heel to toe, alleviate reservoir pressure variation along the laterals, decrease coning or cusping of gas and water, and control gas or water production from offending laterals. Advanced well completion technology, which improves well productivity and maximizes sweep, is becoming the main stream development technology in Saudi Aramco. Numerous future wells and reentries are planned as complex architecture wells with smart completions. Realizing the important role of reservoir simulation, and the difficulties of modeling and optimizing of these complex architecture wells, Saudi Aramco embarked, in 2002, to develop simulation technologies for the evolving complex architecture wells with smart completions. In-house simulation and optimization efforts for complex architecture wells with smart completions have increased drastically since 2002. In fact, two industry joint projects, with a service provider, developed a new simulation workflow for the complex architecture wells with smart well completions. This paper will present simulation, design and optimization of four field cases with complex architecture wells equipped with ICD and ICV. Well configurations, geologic uncertainty and placements of ICD and ICV along the laterals are optimized using the neural network, genetic algorithms, and proxy models. Introduction Worldwide drilling of horizontal wells increased in the mid-1980. Beliveau (Beliveau 1995) compared production performance of horizontal wells with offsetting vertical wells. He calculated the production improvement factor (PIF) for 1306 horizontal wells from 230 fields around the world. The calculated PIF's showed log-normal distribution caused by geologic heterogeneities compounded by mechanical drilling and completion effects. The results revealed a mode PIF of 2, a median PIF of 3, and a mean PIF of 4. One benefit of horizontal wells is that they can seek out more sweet spots (more permeable area or zone) by drilling through or contacting more reservoir rock. Many other factors such as length of the horizontal laterals, wellbore configuration, formation damage (skin), reservoir pressure profiles, unexpected fractures, and baffles affect the rate distribution along the horizontal wellbore.
This paper presents a case study of a vertical interference test conducted in a single well. The investigation in this dual lateral completion was conducted to determine the effective vertical permeability between the pulsing horizontal lateral and the lower section of the vertical wellbore used for observation. This case study showed the presence of a thin layer with extremely high permeability, which intersected both the horizontal lateral and the vertical wellbore (also referred to as a stratiform Super-K). Simulations along with geological and production log data indicated that the Super-K layer was not aerially extensive. Because of the layered nature of the reservoir, presence of a Super-K layer and the multiphase conditions, a numerical well test simulator was used to analyze the horizontal well buildup and the vertical interference test. The test was designed to be able to analyze the horizontal well pressure data in conjunction with the pulse interference data for better reservoir characterization. The paper details the steps followed in this successful integration of all sources of data in the test analysis. Introduction Determination of the vertical permeability in a reservoir is very important in predicting well performance and planning the effective depletion strategy of a reservoir. Vertical permeability can be one of the most important parameters to consider when horizontal wells are drilled to drain oil in a reservoir with bottom water (aquifer or injected water) or a gas cap. Vertical interference tests have been commonly used to determine the horizontal and vertical permeability near a well by analyzing the pressure response induced across the observation perforations by production at the active set of perforations. Burns1 and later Prats2 first introduced the calculation of vertical permeability. Falade and Brigham3,4 developed the most widely used vertical pulse test analysis technique. The method uses sets of correlation curves relating a dimensionless pulse length and dimensionless pulse amplitude. Earlougher5 presented a good summary of these methods. Bremer, et al6 provided a technique for calculating the vertical permeability of a low permeability layer separating two higher permeability zones. Abbaszadeh, et al7 addressed interference testing in reservoirs with conductive faults or fractures. This case study presents the results of a pulse test conducted to determine the vertical permeability between the active horizontal lateral and the lower section of the vertical well bore used for observation. Additional complications in this case study were the layered reservoir between the pulsing horizontal and the vertical well and multiphase conditions. The pressure data at the horizontal pulsing well and the interference pressure data at the vertical well were analyzed separately. The case study also shows evidence of a stratiform Super-K layer that was intersected by both the vertical well and the horizontal lateral. The Super-K layer is a thin layer of multi-Darcy permeability that is commonly seen in Middle East carbonate reservoirs. Analytically, the horizontal well test data can be matched to a model of a horizontal well intersecting vertical fractures in a homogenous reservoir. However, numerical analysis of the test data after integrating the log and production data, suggests a more likely solution of a layered reservoir with a limited Super-K layer.
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