A New Approach to Gas Lift Optimization Using an Integrated Asset Model
Authors: Gutierrez Fernando Alberto , Hallquist Aron Edward , Shippen Mack Edward , Rashid Kashif 
Published: February 2016

Abstract
One of the most common methods of increasing production in oil fields is through the continuous injection of lift gas into the tubing. The injected gas reduces the bottomhole pressure, thereby allowing more oil to flow into the well. The optimal amount of lift gas to inject into individual wells depends on a number of factors including inflow performance, tubing and surface hydraulics. Additionally, careful consideration must be given to operating constraints including cost, handling capacities, compression requirements and the availability of lift gas.
In traditional gas lift optimization projects, a gathering network model is used to calculate the optimal amount of lift gas to inject into each well based on static boundary conditions at the reservoir and processing facility. However, as reservoir conditions change over time, lift gas requirements will change as will operating constraints. The design of the processing facilities will need to accommodate these changes while taking into account the power requirements for compression and treatment processes. By including the reservoir and processing components in an integrated model together with the gathering network, static boundary conditions become dynamic, enabling a true system-wide optimization that greatly enhances field planning strategies in the area of reservoir management.
A case study is presented that illustrates how this concept is applied to an oil field during the conceptual design stage for life of field forecasting.

Introduction
Optimization of oil and gas production occurs in various Reservoir Management cycles depending on the timescale involved in the decision-making process (Fig. 1).
Figure 1: Reservoir Management cycles
The Field Management cycle is a multidisciplinary practice which involves detailed numerical modeling of each system component and analysis of the economic impact of significant capital expenditure projects. During this cycle, various field development strategies are evaluated to determine optimal system design and operation. Examples include planning of step-out and in-fill drilling programs, analysis of enhanced oil recovery methods, and facilities sizing and design.
The Production Optimization cycle involves a thorough analysis of production data using analytical methods and numerical simulation tools such as nodal analysis. Additionally, well tests and production logs are performed to gain a better understanding of well characteristics and behavior. This information is used to identify problem wells and opportunities for increasing production. Examples include well workovers, zonal isolation, artificial lift installations, upgrades of field equipment, and remedial operations to mitigate flow assurance issues.
During the Operations Efficiency cycle, daily monitoring and surveillance activities take place based on high-frequency field data collected through SCADA systems. To achieve optimal operations efficiency, adjustments may be made in existing field equipment. Example control devices include choke settings, gas lift injection rates, production routing, and pump/compressor speeds. These devices are often manipulated through remote actuation, which means that the engineer can make an adjustment from the office and receive quick feedback on the result.