Evaluation of explicit coupling between reservoir simulator and production facilities system

Orientador: Denis José SchiozerDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de GeociênciasResumo: Várias metodologias de acoplamento entre reservatórios e sistemas de produção têm sido aplicadas na indústria de petróleo nos últimos anos devido à necessidade de modelar adequadamente projetos de produção de petróleo cada vez mais complexos, que envolvem a solução integrada dos modelos que representam o escoamento de fluidos desde o reservatório até a superfície. Estas metodologias são utilizadas para fazer a previsão da produção de múltiplos reservatórios, compartilhando plataformas de produção com capacidades de produção e injeção limitadas gerenciadas por sistemas de produção complexos. Elas podem ser agrupadas em dois tipos básicos: metodologias de acoplamento implícito e explícito. A metodologia explícita é uma possível escolha para integrar simulações porque permite acoplar simuladores distintos para modelar o sistema com um todo adequadamente e também fornecer flexibilidade no estudo de alternativas de gerenciamento de poços. Esta metodologia, contudo, deve ser testada para verificar a qualidade dos resultados e eficiência. Desta forma, um estudo de validação da metodologia de acoplamento explícita é apresentado neste trabalho onde o sistema de produção é testado em condições operacionais comuns durante a produção e injeção de fluidos, verificando vantagens e limitações da metodologia explícita. Alguns métodos para o melhoramento da resposta explícita são propostos e avaliados. Um exemplo de aplicação mostra o ganho na flexibilidade de priorização de poços no gerenciamento de grupo obtido pelo uso de uma metodologia externa ao simulador de reservatórios. O acoplamento explícito, como implementado, mesmo com alguns problemas relacionados a instabilidade da solução numérica em situações específicas, apresentou resultados satisfatórios para a integração entre os simuladores, honrando as restrições operacionais fixadas nos casos de avaliação. Algumas análises em relação ao tempo total de simulação acoplada são apresentadas, mostrando uma não dependência do tamanho do problema em relação ao tempo total gastoAbstract: Various methodologies to model the coupling of reservoirs and production systems have been applied in the oil industry in recent years due to the need to model properly the integrated solution of models that represent the flow of fluids through the reservoir to the surface. These methodologies are used to forecast production of multiple reservoirs, sharing production facilities with limited capacities ruled by complex systems. They can be grouped into two basic types: implicit and explicit coupling methodologies. Explicit methodology can be an efficient choice to integrate simulations because it allows coupling adequate simulators to model the whole system and also to add flexibility to study well management alternatives. A validation study of explicit coupling methodology is presented in this work where the production system is tested on common operating conditions during production and injection of fluids, verifying benefits and limitations of the methodology. Some methods for improving the explicit response are proposed and evaluated. An example of application verifies the gain of flexibility in well prioritization by the group management obtained by use of an external methodology for reservoir simulator. The explicit coupling, as implemented, even with some problems related to instability of numerical solution in specific situations, has shown a satisfactory result for the integration between the simulators, honoring operating constraints. Some analyses about elapsed time of coupling simulation are shownMestradoReservatórios e GestãoMestre em Ciências e Engenharia de Petróle

A correction methodology for explicit coupling between reservoir and production system simulators

Various methodologies to model the coupling of reservoirs and production systems have been applied in the oil industry in recent years due to the need to model properly the integrated solution of models that represent the flow of fluids through the reservoir to the surface. Explicit methodology can be an efficient choice to integrate simulations because allows coupling adequate simulators to model the whole system and also to grant flexibility in study of well management alternatives. Several authors have shown the limitations of explicit methodology coupling reservoirs and production systems, such as errors due to the inadequate choices of time step and boundary conditions. The objective of this work were formulated a theoretical foundation to support the adopted IPRc correction methodology, comparing with observed well bottom hole pressure data from reservoir simulation, and validate explicit coupling methodology for producer wells, applying in cases of known response in common situations of well operation in production and injection of fluids. The explicit coupling between reservoir simulator and production systems was implemented obtaining satisfactory results when compared with uncoupled and decoupled methodologies221111126ASME - 31st International Conference on Ocean, Offshore and Arctic Engineerin

Influence of well management in the development of multiple reservoir sharing production facilities

Well prioritization rules on integrated production models are required for the interaction between reservoirs and restricted production systems, thus predicting the behavior of multiple reservoir sharing facilities. This study verified the impact of well management with an economic evaluation based on the distinct prioritizations by reservoir with different fluids. We described the impact of the well management method in a field development project using a consolidated methodology for production strategy optimization. We used a benchmark case based on two offshore fields, a light oil carbonate and a black-oil sandstone, with gas production constraint in the platform. The independent reservoir models were tested on three different approaches for platform production sharing: (Approach 1) fixed apportionment of platform production and injection, (Approach 2) dynamic flow-based apportionment, and (Approach 3) dynamic flow-based apportionment, including economic differences using weights for each reservoir. Approach 1 provided the intermediate NPV compared with the other approaches. On the other hand, it provided the lowest oil recovery. We observed that the exclusion of several wells in the light oil field led to a good valuation of the project, despite these wells producing a fluid with higher value. Approach 2 provided the lower NPV performance and intermediate oil recovery. We found that the well prioritization based on flow failed to capture the effects related to the different valuation of the fluids produced by the two reservoirs. Approach 3, which handled the type of fluids similarly to Approach 1, provided a greater NPV and oil recovery than the other approaches. The weight for each reservoir applied to well prioritization better captured the gains related to different valuation of the fluids produced by the two reservoirs. Dynamic prioritization with weights performed better results than fixed apportionment to shared platform capacities. We obtained different improvements in the project development optimization due to the anticipation of financial returns and CAPEX changes, due mainly from adequate well apportionment by different management algorithm. Well management algorithms implemented in traditional simulators are not developed to prioritize different reservoir wells separately, especially if there are different economic conditions exemplified here by a different valuation of produced fluids. This valuation should be taken into account in the short term optimization for wells

A CORRECTION METHODOLOGY FOR EXPLICIT COUPLING BETWEEN RESERVOIR AND PRODUCTION SYSTEM SIMULATORS

Various methodologies to model the coupling of reservoirs and production systems have been applied in the oil industry in recent years due to the need to model properly the integrated solution of models that represent the flow of fluids through the reservoir to the surface. Explicit methodology can be an efficient choice to integrate simulations because allows coupling adequate simulators to model the whole system and also to grant flexibility in study of well management alternatives. Several authors have shown the limitations of explicit methodology coupling reservoirs and production systems, such as errors due to the inadequate choices of time step and boundary conditions. The objective of this work were formulated a theoretical foundation to support the adopted IPRc correction methodology, comparing with observed well bottom hole pressure data from reservoir simulation, and validate explicit coupling methodology for producer wells, applying in cases of known response in common situations of well operation in production and injection of fluids. The explicit coupling between reservoir simulator and production systems was implemented obtaining satisfactory results when compared with uncoupled and decoupled methodologies

Production strategy optimization based on iterative discrete Latin hypercube

This paper proposes a new iterative discrete Latin hypercube sampling based method to maximize the objective function (OF) in production strategy optimization. This methodology adequately treats posterior frequency distributions of discrete random variables and maximizes non-necessarily monotonic objective functions within discontinuous search spaces and many local optimums. To validate the method, we used an exhaustive process with an net present value (NPV) proxy, as the objective function, to be maximized. Using as an application case, the benchmark UNISIM-I-D reservoir model, based on Namorado field, Campos basin, Brazil, the method successfully maximized the NPV in the intermediate phase of production strategy optimization, and even compared favorably with a well-established optimization methodology. Population based optimization using discrete Latin hypercube sampling best suited this methodology, with consistent convergence to global optimum, few OF evaluations and the simultaneous multiple numeric reservoir simulations runs. This easy to use, reliable methodology with low computational time costs is an interesting option for optimization methods in problems of production strategy design related to the oil industry3882473248

SIMULATION OF NATURALLY FRACTURED RESERVOIRS USING SINGLE-POROSITY EQUIVALENT MODELS

Brazilian Pre-Salt reservoirs are composed of very heterogeneous carbonate rocks with high permeability layers. Double-porosity models are usually applied for the simulation of such systems. In double-porosity models, the rock matrix and the fractures are idealized as two different porous media, modeled as two spatially coincident grids related by a transfer function. However, double-porosity models require solving more equations and, consequently, demand more computational time to simulate than conventional single-porosity reservoir models. An alternative to simulate heterogeneous reservoirs more efficiently is to use pseudo properties that account for both media in a single-continuum equivalent model. This work presents a methodology to obtain similar results of double-porosity models through the use of conventional single-porosity reservoir models with pseudo properties. The methodology is applied to 280 homogeneous isotropic models composed by different combinations of properties, classified accordingly to characteristic naturally fractured reservoir parameters. For 97% of the tested models, the methodology was able to obtain single-porosity equivalent models that resemble the behavior of double-porosity with error below 10%. For the availed cases, the use of single-porosity models implies a reduction of up to 33 times in computational time, which may allow more studies in order to obtain better reservoir management

Development of a special connection fracture model for reservoir simulation of fractured reservoirs

The significant world oil and gas reserves related to naturally fractured carbonate reservoirs adds new frontiers to the development of upscaling and numerical simulation procedures for reducing simulation time. This work aims to accurately represent fractured reservoirs in reservoir simulators within a shorter simulation time when compared to dual porosity models, based on special connections between matrix and fracture mediums, both modeled in different grid domains of a single porosity flow model.For the definition of special connection fracture model (SCFM), four stages are necessary: (a) construction of a single porosity model with two symmetric structural grids, (b) geomodelling of fracture and matrix properties for the corresponding grid domain, (c) application of special connections through the conventional reservoir simulator to represent the fluid transfer between matrix and fracture medium, (d) calculation of the fracture-matrix fluid-transfer. For a proper validation, we apply our methodology in a fractured reservoir type II (tight matrix with flow controlled by fractures) and consider a probabilistic framework regarding geological and dynamic uncertainties. The probabilistic approach of SCFM under several static uncertainties revealed a good dynamic matching with DP. Under three rock-wettability scenarios (water-wet, oil-wet and intermediate-wet) the dynamic matching with DP is preserved. Furthermore, SCFM did not present convergence issues, considering all probabilistic realizations.The results revealed that the new method can be applied to commercial flow simulators in fractured reservoirs and it presents itself as a solution to reduce simulation time without disregarding the upscaling and dynamic representation of dual porosity flow models183The authors are grateful to the Center of Petroleum Studies (Cepetro-Unicamp/Brazil), PETROBRAS S/A, Grant No. 0050.0100204.16.9, UNISIM, ANP, Petroleum Engineering Department (DEP-FEM-Unicamp/Brazil) and Energi Simulation Foundation (formerly FCMG) for their support of this work. The authors are also grateful to Schlumberger Information Solution for the use of Petrel® and the Computer Modeling Group for the use of Black Oil reservoir simulator IMEX

The impact of time-dependent matrix-fracture fluid transfer in upscaling match procedures

Matrix-to-fracture transfer functions assume that fractures are instantaneously filled with water, leading to constant, time-independent shape factors. However, the water filling fracture regime, which can be observed for some conditions such as small injection rates, does not lead to constant shape-factors and is difficult to solve using commercial flow simulators. The purpose of this study is to (1) show the impact of rock wettability in reservoir simulation and upscaling procedures, and, (2) apply an upscaling matching procedure based on time-dependent matrix-fracture fluid transfer term. This work shows that the increase of rock preference for water can lead to upscaling limitations due to the partially immersed fractures behavior observed in cases with small fracture apertures and small injection rates, for water-wet rocks. A time-dependent matrix-fracture fluid transfer term was proposed for upscaling matching procedures. The developed method solves the limitation of time-independent shape factors and allows the dual porosity flow model to properly represent the dynamic behavior for different wettability scenarios. This work aims to contribute for understanding the impact of rock wettability in upscaling and reservoir simulation of fractured reservoirs and, provides solutions for flow simulation of dual porosity flow models under a water filling-fracture regime, which is common in water-wet rocks146752763The authors are grateful to the Center of Petroleum Studies (Cepetro-Unicamp/Brazil), PETROBRAS-Brazil (Grant Agreement No.0050.0022715.06.4), UNISIM and the Petroleum Engineering Department (DEP-FEM-Unicamp/Brazil) for their support of this work. The authors are also grateful to Schlumberger Information Solution for the use of Petrel® and Computer Modelling Group for the use of Black Oil reservoir simulator IME