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Results
Abstract 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 m. 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.
- South America > Colombia > Llanos Basin (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-7 > Peregrino Heavy Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-47 > Peregrino Heavy Field (0.99)
- South America > Venezuela (0.91)
Abstract The description of heptanes and heavier components (C7+) in reservoir fluids can be important for equation of state (EOS) predictions of phase and volumetric behavior. This paper describes a procedure for C7+ characterization of heavy oil based on crude assay data which are typically measured for refining and marketing applications. C7+ characterization is defined as (1) modeling the molar distribution that quantifies molar (mass) amounts and molecular weights of discrete plus fractions, (2) estimating specific gravity and normal boiling point of plus fractions, and (3) estimating EOS and viscosity-model parameters Tc, pc, ω, Vc, s (volume shift) and binary interaction parameters (BIPs) kij of plus fractions. From crude assay data, we use the mass fractions and overall sample molecular weight to determine the parameters for gamma molar distribution parameters – shape (α), lower bound (η) and average plus molecular weight (Mo) in the gamma distribution model. The molar distribution model, together with measured assay-cut specific gravity and boiling point data, are used to determine parameters in the Soreide correlation describing specific gravity-molecular weight relationship. The inter-correlation of assay data is also affected by correlation used between molecular weight, boiling point, and specific gravity. We use a parameter, fTwu, where fTwu=1 honors the Twu correlation exactly, while fTwu= 0 honors a pure-paraffinic correlation between molecular weight and boiling point (independent of specific gravity). Viscosities of each fraction are correlated against measured data and/or standard-pressure liquid viscosity estimates from the Orrick-Erbar correlation. We use the Lorentz-Bray-Clark (LBC) correlation, where fraction critical volumes are adjusted to give consistency between the LBC estimates for each fraction individually. This approach to determining the critical volumes has proven useful in making the LBC more predictive for overall oil mixture viscosities at reservoir conditions.