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Abstract Intelligent well completion technology provides a broad spectrum of value generating functionality for oil and gas field operations, all derived from the ability to monitor and control fluid production and injection by zone in real-time. A major barrier to intelligent well technology adoption has been the lack of method to quantitatively define the value associated with various applications of the technology. Most companies often use a Net Present Value (NPV) analysis to quantify and rank project proposals. Due to the nature of intelligent well technology, NPV analysis is not applicable to a wide range of applications and invariably underestimates the value associated with the technology. Operators intuitively understand the benefits of the technology, but are unable to represent it with conventional NPV valuation techniques, and thus are unable to justify intelligent well completion deployment against more conventional, better-understood, but lower valued, completion technology. An approach has been developed to define and solve the intelligent well valuation problem using mathematical techniques from the financial community called Real Options analysis, specifically, the concept of Flexibility Options. It quantifies the option value derived from the flexibility offered by the application of intelligent well technology enabling the ability to monitor and respond to reservoir uncertainties as it is manifested throughout the field life cycle. Case study has been developed using well data from field in the Gulf of Mexico region incorporating the level of smartness, the associated system reliability, and the projected reservoir performances to quantify the flexibility option value offered through the implementation of intelligent well over conventional completion technology. This paper will support the conclusions that application of field proven intelligent well technology can increase asset value. The case study use intelligent well critical variables to quantify the value of operating flexibility derived from implementing intelligent well technology. However, some important points should be considered. Firstly, equipment reliability is vital in the valuation. Secondly, economic justification including option value is required to assess the business case in face of reservoir uncertainties. Thirdly, the relationship between resolving reservoir uncertainty, system reliability and functionality must be understood to realize "The right level of Smartness..." Introduction Intelligent well technology is an emerging technology for the oil and gas industry. It provides a broad spectrum of value generating functionality for oil and gas field operations; all derived from the ability to collect, transmit, and analyze completion, production and reservoir data. It also allows the selective zonal monitoring and control of fluid production and injection real-time to optimize the production process. Adoption of intelligent well technology has been slow to maturity due in part to the lack of a viable method to quantitatively define the value associated with various applications of the technology. This technology minimizes operational risk by better leveraging technically advanced well bores (multilateral and extended reach horizontals) as well as commingling production from separate reservoirs to increase total recovery through time. The systems optimize flow regulation by shutting (on/off) and choking water/gas ingress after breakthrough. Some intelligent well systems can measure flow rate and water-cut from individual zone to optimize artificial lift efficiency and control production from (or injection into) zones with varying permeability.
Abstract Intelligent wells are widely used around the world and they have the potential to significantly improve oil production or control water production of wells and fields. However, in many cases, the definition of the number and position of valves is still made considering only the well without evaluating if the decision to use them can change other important aspects of the production strategy. This article presents a study to evaluate some relevant aspects of the inclusion of intelligent wells in a more global study of production strategy selection. Such inclusion is an important step in the precise evaluation of the benefits of intelligent valves. The methodology comprises the economic optimization of a production strategy under different limits of platform flow capacity, the optimization of the number and position of valves (intelligent wells), including and excluding conventional well operation. This study was applied to the UNISIM-I-D benchmark case, starting with a previously optimized production strategy, regarding type, number and position of wells, well-opening sequence and platform flow capacity in 9 different geological scenarios. The optimization methodology uses a complex workflow to test different strategy alternatives using a genetic algorithm and a methodology to optimize the number and position of valves. We showed that the use of intelligent wells can significantly alter the water flow capacity and the operational design of wells. However, for this specific case, the use of intelligent wells was not able to modify oil production and water injection flow capacity. Intelligent well application was viable for 7 out of 9 geological scenarios with the number of valves varying from 1 to 14. The intelligent-well application improved the total NPV from 0% to 1.5%. The platform water flow capacity could be reduced by at least 30% if intelligent valves were implemented. These results are quite different when a less precise optimization methodology is applied, yielding an overestimation of an intelligent well. To conclude, the application of intelligent wells was viable for most of the scenarios. Although intelligent wells present low impact on NPV, they can modify the design of platform capacity significantly. This fact suggests that the optimization of intelligent wells must be combined with the optimization of the platform water flow capacity and the conventional well operation optimization. This work provides important information for reservoir engineers who use reservoir simulation to optimize production strategy. Currently, in many cases, intelligent wells are only evaluated after the selection of the platform design. We have proved that the combined optimization can yield a different production strategy design. In addition, we have also proved that the evaluation of intelligent wells viability without an adequate optimization of conventional well operation overestimated the number and the value of valves.
Abstract We examine the two-year history of an extended reach dual-lateral well, in which lateral production has been controlled by downhole flow control valves to minimize water production and optimize the lift effected by a high-horsepower electrical submersible pump. We assess the impact of downhole flow control on production performance by a modeling exercise consisting of refining a region surrounding the wellbore to reproduce the observed production history, and then forecasting the performance of that refined model under alternate completion scenarios. This methodology can also be used to select valve settings that are most advantageous to production. Introduction Wytch Farm, the largest onshore oilfield in Europe, is situated in the south of England, and is operated by BP-Amoco. The bulk of reserves and production comes from the Sherwood formation, which lies some 5120–5625 ft TVDSS beneath Poole Harbor in Dorset, England. The offshore sector of the field has been developed from land using extended reach wells. Production plateaued at just over 100,000 bopd in 1995 and held into 1998; current production is about 60,000 bopd. The field is under strong water-drive and producing at increasing water-cut. The faulted parts of the field are prone to early water production due to the fault-induced increased connectivity to the underlying aquifer. The wells are equipped with ESPs to produce the field to high water-cut and enhance recovery. Reference 1 contains an informative overview of field history. Background Well M-2 was drilled in 1994, went to high water-cut in 1997 and was abandoned in 1998. M-2 was sidetracked to reach two targets and the well was renamed M-15. Three hydraulically controlled valves were placed in the well to control the influx from each lateral independently. Two valves were installed to control the production of the high-rate, high water-cut northern lateral; the third was used to control production of the southern lateral. Figure 1 shows the trajectories of the previously producing well and the two new producing laterals. Figure 2 is a diagram of the segment surrounding the junction of the two producing laterals. Reference 2 treats the completion aspects of this installation; Reference 3 summarizes the operational experience with this well. The objectives of the current study were to –quantify the benefits of the intelligent completions: examine optimization of valve settings; and examine the use of the near-wellbore modeling approach. Well Behavior Table 1 is a summary of key production rates with each lateral open and with both laterals open. The northern lateral is capable of higher fluid rates but has a higher water-cut. The two laterals when produced together mutually interfere with regard to production of fluid. The overall production strategy is then to produce the lower water-cut southern laterals unchoked and control the northern lateral. Table 2 contains average values of the basic rock and fluid properties used in the study. Figure 3 is a summary of selected tests during the first year of production. The upper plot shows the total fluid and oil production from the well. The lower plot shows the position of each valve. The well was produced from each lateral separately from Feb. until Nov. of 1999.
Abstract Even temperature conformance along the length of the horizontal well is key to maximizing Steam Assisted Gravity Drainage (SAGD) production rates. When temperature logs are run in SAGD producers, temperature variations of greater than 50°C between the hottest and coldest spots are commonly observed. We theorize that this temperature distribution is related to an inflow distribution, and that production rates could be improved if this temperature variance was narrowed. It is difficult to influence conformance with traditional SAGD producer well design. Flow areas are large, and liquid velocities are low, resulting in small frictional pressure losses. It is not possible to impose a materially different drawdown on hot and cold spots along the horizontal with typical well completion methods. A field trial is ongoing at the Firebag project in which a production well is equipped with intelligent completion technology. The test well's horizontal liner section is split into four hydraulically isolated zones, with each zone having the ability to provide flow or isolation from the reservoir. The well completion is equipped with optical pressure and temperature (P/T) gauges and distributed temperature sensing (DTS) technology which monitors each segment's performance during operations. The capability to independently and immediately manipulate each segment's production inflow will provide the operator the ability to evaluate the influence of an intelligent completion design on a well's conformance and ultimate oil recovery.