Implementations of smart-field strategies with intelligent completions, i.e., interval control valves and interval control devices, are growing in the oil industry. Yet, there is still resistance by some companies because of concerns for (1) provable long-term value in terms of oil recovery and returns; (2) risk of valve failures affecting well integrity and performance; (3) lower returns of actual results relative to predicted results (i.e., overoptimistic projections, often from simulation); and (4) uncertainty as to the most effective future operational practices. This paper presents a systematic analysis of well rates and pressures as predicted by simulation for a long horizontal well. The paper investigates long-term value, analyzes impact of valve failure on production, provides estimates on the impact of reservoir uncertainty on performance, and demonstrates production improvements from effective operational control procedures for the horizontal well, for a multi-lateral well, and for a 20-production well waterflood. The paper validates and implements a methodology using simulation-based analysis and automated procedures to optimize valvecontrol strategies: oil production is maximized, while water production is better managed. Two control strategies are investigated and compared against a do-nothing approach: a fixed control strategy and a flexible control strategy.

Saudi Aramco has completed more than 100 multilateral wells with intelligent completions to monitor and control the inflow from the laterals in realtime without well intervention. The intelligent completion typically consists of isolation packers, multi-position downhole valves and downhole gauges. Field data has confirmed that the systems are functional in controlling inflow from laterals and that the flow characteristics of the downhole valves are varied due to different completion design and productivity index of producing zones. A field review was initiated to optimize the operation of the existing wells and to design a standardized valve design that suits different well completions and reservoirs.This paper illustrates a case study detailing comprehensive analysis of downhole valves performance and design. It presents the process used to improve downhole valve design based on field data. The new design provides higher level of control at lower flow rates, hence enables finer adjustment of distribution of inflow among different laterals or segments. The modeling work is based on a new operating envelope so that inflow control valves can be used to produce rates that satisfy both reservoir management strategy and well production scheme. The modified insert chokes has been flow tested and installed in recent wells' completions. These wells will be flow tested to evaluate the performance of the new downhole control valves.

Implementations of smart-field strategies with intelligent completions, i.e., interval control valves and interval control devices, are growing in the oil industry. Yet, there is still resistance by some companies because of concerns for (1) provable long-term value in terms of oil recovery and returns; (2) risk of valve failures affecting well integrity and performance; (3) lower returns of actual results relative to predicted results (i.e., overoptimistic projections, often from simulation); and (4) uncertainty as to the most effective future operational practices. This paper presents a systematic analysis of well rates and pressures as predicted by simulation for a long horizontal well. The paper investigates long-term value, analyzes impact of valve failure on production, provides estimates on the impact of reservoir uncertainty on performance, and demonstrates production improvements from effective operational control procedures for the horizontal well, for a multi-lateral well, and for a 20-production well waterflood. The paper validates and implements a methodology using simulation-based analysis and automated procedures to optimize valvecontrol strategies: oil production is maximized, while water production is better managed. Two control strategies are investigated and compared against a do-nothing approach: a fixed control strategy and a flexible control strategy.

Field B is undergoing implementation of an accelerated development plan and around 40 wells have been drilled so far. Due to the volatile nature of the crude and high GOR, gas recycling was identified as the reservoir pressure maintenance strategy. There are 4 gas injectors in the field injecting into two reservoirs. As per the original development plan, no artificial lift was envisaged and model results showed sustained natural flow from the well. However, after drilling and completing the wells, it was found that sand connectivity and continuity were far more complicated than expected. This resulted in depleting the reservoirs in certain compartments thus requiring some form of artificial lift. Further, this field will be undergoing a gas blow down project from 2015 onwards, and the challenge to the Well & Reservoir Management Team was to maximize recovery before gas blow down. A series of options were considered and gaslift was selected as the most viable artificial lift mode. Lead time for the conventional gaslift and the cost associated with special piping materials were adversely impacting the plans and an innovative idea of auto gaslift was proposed as an alternate to conventional gaslift. Accordingly, Well #XX was selected for application of this technology. Auto gaslift uses high pressure gas from a gas reservoir admitted into the tubing using an intelligent completion & special ICV with gas trim and straddle packers. A down hole pressure gauge installed on top of the packer will assist in tuning the choke settings during auto gas lifting. Based on the success of this well, 5 more wells were re-completed with Auto gaslift technology resulting in increasing the production by 50% from the field. Currently, this technology is being evaluated for other fields in the company's assets. This paper explains the technology of Auto gaslift, details of intelligent completion used in the wells, results obtained, gaslift optimization, lessons learned and way forward for artificial lift in other fields with similar reservoir conditions.