A cooperative approach for distributed task execution in autonomic clouds

Virtualization and distributed computing are two key pillars that guarantee scalability of applications deployed in the Cloud. In Autonomous Cooperative Cloud-based Platforms, autonomous computing nodes cooperate to offer a PaaS Cloud for the deployment of user applications. Each node must allocate the necessary resources for customer applications to be executed with certain QoS guarantees. If the QoS of an application cannot be guaranteed a node has mainly two options: to allocate more resources (if it is possible) or to rely on the collaboration of other nodes. Making a decision is not trivial since it involves many factors (e.g. the cost of setting up virtual machines, migrating applications, discovering collaborators). In this paper we present a model of such scenarios and experimental results validating the convenience of cooperative strategies over selfish ones, where nodes do not help each other. We describe the architecture of the platform of autonomous clouds and the main features of the model, which has been implemented and evaluated in the DEUS discrete-event simulator. From the experimental evaluation, based on workload data from the Google Cloud Backend, we can conclude that (modulo our assumptions and simplifications) the performance of a volunteer cloud can be compared to that of a Google Cluster

Modelling of a Gas Cap Gas Lift System

Imperial Users onl

Developments in modeling and optimization of production in unconventional oil and gas reservoirs

textThe development of unconventional resources such as shale gas and tight oil exploded in recent years due to two key enabling technologies of horizontal drilling and multi-stage fracturing. In reality, complex hydraulic fracture geometry is often generated. However, an efficient model to simulate shale gas or tight oil production from complex non-planar fractures with varying fracture width along fracture length is still lacking in the petroleum industry. In addition, the pore size distributions for shale gas reservoirs and conventional gas reservoirs are quite different. The diffusivity equation of conventional gas reservoirs is not adequate to describe gas flow in shale reservoirs. Hence, a new diffusivity equation including the important transport mechanisms such as gas slippage, gas diffusion, and gas desorption is required to model gas flow in shale reservoirs. Furthermore, there are high cost and large uncertainty in the development of shale gas and tight oil reservoirs because of many uncertain reservoir properties and fracture parameters. Therefore, an efficient and practical approach to perform sensitivity studies, history matching, and economic optimization for the development of shale gas and tight oil reservoirs is clearly desirable. For tight oil reservoirs, the primary oil recovery factor is very low and substantial volumes of oil still remain in place. Hence, it is important to investigate the potential of CO₂ injection for enhanced oil recovery, which is a new subject and not well understood in tight oil reservoirs. In this research, an efficient semi-analytical model was developed by dividing fractures into several segments to approximately represent the complex non-planar fractures. It combines an analytical solution for the diffusivity equation about fluid flow in shale and a numerical solution for fluid flow in fractures. For shale gas reservoirs, the diffusivity equation of conventional gas reservoirs was modified to consider the important flow mechanisms such as gas slippage, gas diffusion, and gas desorption. The key effects of non-Darcy flow and stress-dependent fracture conductivity were included in the model. We verified this model against a numerical reservoir simulator for both rectangular fractures and planar fracture with varying width. The well performance and transient flow regime analysis between single rectangular fracture, single planar fracture with varying width, and single curving non-planar fracture were compared and investigated. A well from Marcellus shale was analyzed by combining non-planar fractures, which were generated from a three-dimensional fracture propagation model developed by Wu and Olson (2014a), and the semi-analytical model. Contributions to gas recovery from each gas flow mechanism were analyzed. The key finding is that modeling gas flow from non-planar fractures as well as modeling the important flow mechanisms in shale gas reservoirs is significant. This work, for the first time, combines the complex non-planar fracture geometry with varying width and all the important gas flow mechanisms to efficiently analyze field production data from Marcellus shale. We analyzed several core measurements for methane adsorption from some area in Marcellus shale and found that the gas desorption behaviors of this case study deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, such behavior has not been presented in the literature for shale gas reservoirs to behave like multilayer adsorption. The effect of different gas desorption models on calculation of original gas in place and gas recovery prediction was compared and analyzed. We developed an integrated reservoir simulation framework to perform sensitivity analysis, history matching, and economic optimization for shale gas and tight oil reservoirs by integrating several numerical reservoir simulators, the semi-analytical model, an economic model, two statistical methods, namely, Design of Experiment and Response Surface Methodology. Furthermore, an integrated simulation platform for unconventional reservoirs (ISPUR) was developed to generate multiple input files and choose a simulator to run the files more easily and more efficiently. The fracture cost was analyzed based on four different fracture designs in Marcellus shale. The applications of this framework to optimize fracture treatment design in Marcellus shale and optimize multiple well placement in Bakken tight oil reservoir were performed. This framework is effective and efficient for hydraulic fracture treatment design and production scheme optimization for single well and multiple wells in shale gas and tight oil reservoirs. We built a numerical reservoir model to simulate CO₂ injection using a huff-n-puff process with typical reservoir and fluid properties from the Bakken formation by considering the effect of CO₂ molecular diffusion. The simulation results show that the CO₂ molecular diffusion is an important physical mechanism for improving oil recovery in tight oil reservoirs. In addition, the tight oil reservoirs with lower permeability, longer fracture half-length, and more heterogeneity are more favorable for the CO₂ huff-n-puff process. This work can provide a better understanding of the key parameters affecting the effectiveness of CO₂ huff-n-puff in the tight oil reservoirs.Petroleum and Geosystems Engineerin

Surface Drilling Data for Constrained Hydraulic Fracturing and Fast Reservoir Simulation of Unconventional Wells

The objective is to present a new integrated workflow which leverages commonly available drilling data from multiple wells to build reservoir models to be used for designing and optimizing hydraulic fracture treatment and reservoir simulation. The use of surface drilling data provides valuable information along every wellbore. This information includes estimations of geomechanical logs, pore pressure, stresses, porosity and natural fractures. These rock properties may be used as a first approximation in a well-centric approach to geoengineer completions. Combining these logs from multiple wells into 3D reservoir models provides more value including using them in reservoir geomechanics, 3D planar hydraulic fracturing design and reservoir simulation. When using these 3D models and their results in a fast marching method simulator, the impact of the interference between wells can be estimated quickly while providing results like those derived with a classical reservoir simulator. Integrating surface drilling data with 3D reservoir models, hydraulic fracturing design and reservoir simulation into a single software platform results in a fast and constrained approach which allows for a more efficient management of unconventional wells

A Study of Interwell Interference and Well Performance in Unconventional Reservoirs Based on Coupled Flow and Geomechanics Modeling with Improved Computational Efficiency

Completion quality of tightly spaced horizontal wells in unconventional reservoirs is important for hydrocarbon recovery efficiency. Parent well production usually leads to heterogeneous stress evolution around parent wells and at infill well locations, which affects hydraulic fracture growth along infill wells. Recent field observations indicate that infill well completions lead to frac hits and production interference between parent and infill wells. Therefore, it is important to characterize the heterogeneous interwell stress/pressure evolutions and hydraulic fracture networks. This work presents a reservoir-geomechanics-fracturing modeling workflow and its implementation in unconventional reservoirs for the characterization of interwell stress and pressure evolutions and for the modeling of interwell hydraulic fracture geometry. An in-house finite element model coupling fluid flow and geomechanics is first introduced and used to characterize production-induced stress and pressure changes in the reservoir. Then, an in-house complex fracture propagation model coupling fracture mechanics and wellbore/fracture fluid flow is used for the simulation of hydraulic fractures along infill wells. A parallel solver is also implemented in a reservoir geomechanics simulator in a separate study to investigate the potential of improving computational efficiency. Results show that differential stress (DS), parent well fracture geometry, legacy production time, bottomhole pressure (BHP) for legacy production, and perforation cluster location are key parameters affecting interwell fracture geometry and the occurrence of frac hits. In general, transverse infill well fractures are obtained in scenarios with large DS and small legacy producing time/BHP. Non-uniform parent well fracture geometry leads to frac hits in certain cases, while the assumption of uniform parent well fracture half-lengths in the numerical model could not capture the phenomenon of frac hits. Perforation cluster locations along infill wells do not play an important role in determining whether an infill well hydraulic fracture is transverse, while they are important for the occurrence of frac hits. In addition, the implementation of a parallel solver, PETSc, in a fortran-based simulator indicates that an overall speedup of 14 can be achieved for simulations with one million grid blocks. This result provides a reference for improving computational efficiency for geomechanical simulation involving large matrices using finite element methods (FEM)

GAWPS: A MRST-based module for wellbore profiling and graphical analysis of flow units

Several graphical methods have been developed to understand the stratigraphy observed in wells and assist experts in estimating rock quality, defining limits for barriers, baffles, and speed zones, and in particular, delineating hydraulic flow units. At present, there exists no computational tool that bundles the main graphical methods used for defining flow units. This paper introduces an add-on module to the MATLAB Reservoir Simulation Toolbox that contains computational routines to carry out such graphical analyses, both qualitatively and quantitatively. We also describe a new secondary method defined as the derivative of the stratigraphic modified Lorenz plot, which we use to classify depth ranges within the reservoir into barriers, strong baffles, weak baffles, and normal units, based on flow unit speed over those depths. We demonstrate the capabilities of the “Graphical Analysis for Well Placement Strategy” module by applying it to several case studies of both real and synthetic reservoirs.Cited as: Oliveira, G. P., Rodrigues, T. N. E., Lie, K.-A. GAWPS: A MRST-based module for wellbore profiling and graphical analysis of flow units. Advances in Geo-Energy Research, 2021, 6(1): 38-53. https://doi.org/10.46690/ager.2022.01.0