Integrated Field Modeling and Optimization

Integrated Field Modeling and Optimization

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This PhD research investigates production optimization of conventional and unconventional reservoirs by considering compositional and black-oil reservoir fluid properties and presents economic evaluation in terms of a net present value (NPV) formulation.
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Oil and gas continue to be widely used worldwide as energy resources, because new sources of safe energy have not yet been well developed. These conditions have motivated researchers in the area of oil and gas production to investigate new approaches to the application of optimization methods to maximize gas or oil production rates and to minimize production costs.  

This PhD research investigates production optimization of conventional and unconventional reservoirs by considering compositional and black-oil reservoir fluid properties and presents economic evaluation in terms of a net present value (NPV) formulation. In general, unconventional reservoirs are characterized by large volumes that are difficult to develop since the permeability is low (<0.1 mD). A new approach to NPV calculation is introduced in which NPV is taken as the maximum cumulative NPV and not always the value at the end of the simulation. The maximum cumulative NPV has correlation with optimum field operation time using current production and/or injection strategy. The proposed method provides an advantage in determining when a new production strategy and/or management decision should be applied after the optimum field operation time is reached.  

Three new approaches related to oil and gas production performance will be presented in this thesis: (i) a cyclic shut-in strategy for liquid-loading gas wells, (ii) production optimization using an integrated model from subsurface to surface facilities, which is then linked to an economic analysis, and (iii) an optimal injection strategy for oil reservoirs when water and gas injection are available. A framework for decision support tools, based on available software, is implemented and a derivative-free optimization method, the Nelder-Mead Simplex, is applied.  

A cyclic shut-in strategy for liquid-loading gas wells in unconventional gas reservoirs has been studied. An unconventional reservoir is a potential future energy resource offered by new methods of exploration and production. One of the characteristics of an unconventional gas reservoir is low permeability, in which a gas well producing reservoir fluids usually experiences a liquid-loading condition during production. This condition is caused by accumulation of liquid at the bottom of the well, where an increasing liquid column in the well results in hydrostatic back-pressure to the reservoir, destabilizing the multiphase flow in the well, decreasing the gas production rate, and finally killing the well. A cyclic shut-in strategy is introduced to reduce the loss of gas production by increasing the reservoir pressure and gas production thereby will able to push the liquid column up to the surface. The simulation results show consistently that ultimate recovery increases, for both vertical and horizontal fractured wells.  

An integrated field model and optimization may play an important role during production because an integrated model may produce comprehensive operational recommendations. An integrated field model combined with optimization presents many technological challenges in terms efficient algorithms to couple models, as well as models with optimization, and sufficient hardware capability to run the complex model. A benchmark case which consists of three different reservoirs that are linked to a surface facility model has been developed. The surface process model interacts with the three reservoir models through the distribution of available produced gas for reinjection into the three reservoirs. The reservoir and surface process variables are optimized in terms of maximizing asset value. The integrated model and corresponding optimization results provide a benchmark that contributes to academic and industrial knowledge on the potential value of joint optimization of the upstream and downstream parts of the production chain. The benchmark should be valuable as a tool for assessing future alternative methods for production chain optimization.  

An optimal injection strategy for miscible water alternating gas injection is presented as a mixed-integer non-linear problem formulation. A heuristic approach is chosen to solve the problem. The injection strategies include gas injection, water injection, WAG, and a combination of the above injection strategies. The injection strategies are optimized to find the best injection strategy for a particular reservoir. The optimization was conducted for two production strategies: artificial lift and natural flow. The study concluded that a gas-water injection strategy with long-time gas injection and artificial lift was the best scenario for the example used in this study. The scenarios, with an NPV increase of 8 − 31%. Moreover, the injection optimization presented in this study should have significance potential for other miscible oil reservoirs.

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