Well Test Rate Conversion to Compositional Wellstream

Heavy oil fields can be developed using diluent (light oil, condensate, etc.) injection at the well level as a flow improver. However, diluent can also be injected at the surface, as used in Canadian heavy oil production. Benefits of topside diluent injection include among others (1) improved oil/water separation in the surface processing facility, (2) improved viscosity, and (3) better final crude quality. Such blending activities are often associated with additional OPEX due to the high price of diluent, which can add significant costs to a development. This paper describes an Integrated Asset Modelling (IAM) solution designed to minimize the topside diluent requirement while honouring technical and market crude specifications. The case studied is an offshore heavy oil field consistings of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp. The production facilities include a two-stage surface processing facility followed by a coalescer aimed to separate the water from the crude. Diluent is injected in the surface processing facility prior to the second stage separator. Operating variables include (1) the topside diluent injection rate and (2) the temperature of the second stage separator. The difficulty of the production optimization problem lies in the non-linearity of the process and viscosity models, and the consistency of the fluid’s PVT description throughout the production system. The proposed optimization solution is coupled with a reservoir simulator to determine optimal topside diluent requirements over time and foresee eventual bottlenecks in the surface infrastructure design. The proposed solution can also be used as a real-time management tool during the production phase to find the optimal operating point based on real-time data. The optimal operating point ensures the lowest diluent consumption while meeting all system constraints, providing the framework for significant cost savings.

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Diluent Injection Optimization for a Heavy Oil Field

Hoffmann¹,

Astutik²,

Rasmussen

et al. 2016

Day 2 Wed, December 07, 2016

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Past studies have shown that use of diluent injection with ESPs can be an efficient artificial lift method for heavy oil fields. It consists of injecting a light hydrocarbon liquid to reduce the oil density and viscosity. This paper describes an integrated modeling solution designed to maximize the reservoir oil production while minimizing the diluent requirement and keeping the crude oil quality within technical and marketing specifications. The field studied is an offshore heavy oil asset. It consists of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp. The field includes some 60 production wells. Diluent can be injected (1) in each individual well at the ESP and (2) in the surface processing facility prior to the second stage separator. Operating constraints include (1) minimum wellhead pressure, (2) diluent availability, (3) final crude quality specifications, (4) maximum field oil and liquid production rate. The difficulty of the production optimization problem lies in the nonlinearity of the well production curves and viscosity model. In this paper, we develop a Mixed Integer Linear Programming (MILP) formulation by piecewise linearizing the nonlinear behaviors. For each well at each time step, we adjust the black-oil rates from a reservoir simulator to create piecewise linear well performance curves giving the reservoir oil production as a function of diluent injected at the ESP. The proposed integrated solution is used for the entire production life of the field, which is still in the development phase. The solution is coupled with a reservoir simulator (1) to determine optimal diluent requirements over time, (2) forecast field production of reservoir oil, diluent, water and gas, and (3) foresee eventual bottlenecks in the infrastructure design (e.g. limiting constraints). The proposed solution can easily be used as a Real Time Production Optimization (RTPO) tool to find the optimal operating point based on the latest measurements (or real-time data). The optimal solution ensures the highest field reservoir oil production while meeting all constraints and keeping the diluent consumption at a minimum. The increase of the field oil production rate due to optimal diluent allocation ranges from 2 to 10 %. Cumulative reservoir oil production increases by approximately 3 million std m3. The uniqueness of the solution comes from the integration of all operating constraints into a single mathematical formulation. The computational time (1s – 10s) of the proposed solution outperforms any classical nonlinear approach. This allows running many sensitivity analyses of the entire integrated asset model.

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Well Test Rate Conversion to Compositional Wellstream

Cited by 7 publications

References 3 publications

Sampling petroleum fluids

Sampling petroleum fluids

Optimal Management of Topside Diluent Injection for a Heavy Oil Field

Diluent Injection Optimization for a Heavy Oil Field

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