The intelligent well system (IWS) is normally operated with multiple-zone production/injection in the commingled condition, which makes it difficult to predict the effect of IWS operations on well flow performance and zonal deliverability. This is because:The production string, downhole control equipment and isolation tools separate production fluids into different flow paths (tubular/annulus), and the different flow paths have different resistance to each zone's outflow;the reservoir and fluid properties of individual zones are normally different, and these varying properties will cross-impact the outflow of each other's zones when fluids are commingled;downhole choking operations will impact the wellbore pressure profile, thus impacting the production profile from each zone; andSimulate the fluid temperature profile and the effect on pressure and flow profile for the IWS completion is a complex task. The current published works have not covered the whole spectrum. To address this situation, an analysis tool has been developed, combining the developed comprehensive thermal model with integrated inflow performance relationship (IPR) technology and innovative operation point searching algorithm. For any downhole choking operation scenario, the flow allocations and profiles of wellbore pressure, temperature and fluid velocity can be predicted. This provides the operators insight into how to choke the downhole valves to meet the production enhancement target. It also gives an insight of how we customized the design of the downhole valve settings to achieve the production objectives. In addition, the threshold pressure at commingle point to control crossflow can be predicted through this technology, which provides potential ability to control/monitor possible crossflow of multiple-zone production through the intelligent well monitoring and control system. For demonstration purpose, a potential case study of a typical deep-water two-zone IWS was used for analysis. Model verifications were provided by comparison with the third-party software. Analysis and comments of the comparison have been provided.

All of the production wells in this field were drilled and completed as horizontal and multi-lateral wells. The well designs range from a single lateral in a single sand body to where the upper and lower horizontal laterals intersect several sand lenses. The oil, an extra-heavy (9 API), high viscosity oil, requires a completion using artificial lift due to the low reservoir pressure, which will not support a column of water. The use of down-hole pressure and temperature sensors with Surface Read-Out (SRO) was an integral part of the original well completions on production wells to monitor the individual well and pump performance. Vertical monitoring wells, drilled and completed through the multiple sand lenses present, expanded the use of down-hole sensors as data was sought on the area extent and pressure drawdown in the various sands being produced. Efforts to determine the contribution to flow and the pressure losses encountered in horizontal wells led to the use of multiple sensors installed at depths along the long horizontal lateral. A change to the drilling of complex multi-lateral wells resulted in the use of tandem sensors to determine the relative contribution to flow from the lower and the upper lateral(s). All of these approaches, combined with the inability to use conventional Production Logging Tool techniques, led to the application of new technology combining fibre optics with multiple sensors to obtain a real time alternative to a PLT. As many as 15 surface read-out sensors were successfully installed in 7000 feet long horizontal well sections with measured depths up to 10,000 feet. Introduction Petrozuata C.A. is a Venezuelan joint venture company that was registered in March 1996 by Conoco Orinoco Inc. and PDVSA (Formerly Maraven S.A.), an affiliate of Petroleos de Venezuela S.A. The Joint Venture is the operator of a property in Eastern Venezuela's Orinoco belt located just East of San Diego de Cabrutica. This field development is part of a large project incorporating a pipeline network to a 120,000 bopd heavy oil upgrader facility at the coast near Barcelona. The heavy oil upgrading facilities processes approximately 120,000 barrels per calendar day of heavy oil to produce approximately 103,000 BOPD of a synthetic crude oil with a 19 to 25 API. The Joint Venture has a 35 year operating life and will require the drilling of over 500 horizontal wells that recover 1.5–2 billion barrels of extra heavy oil during that period. Construction activities commenced in January 1997. Drilling of production wells commenced in August of 1997 with "first oil" achieved in August 1998. The production wells drilling design was modified to a multi-lateral design late in 1999. The Orinoco Belt is on the southern flank of the east-west trending Eastern Venezuela structural basin and contains over 1.2 trillion barrels of oil-in-place (STOOIP). It is divided into four areas (Machete, Zuata, Hamaca and Cerro Negro). This field consists of approximately 57,000 acres (23,050 hectares) of land to be leased for the initial development of the oil field. (Figure 1) Development consists of a pad type layout. Each pad contains, initially 4 to 8 wellheads, with artificial lift pump equipment, space for drilling equipment, a flocculent pit, space for drilling trailers, electrical equipment, a multiphase meter and manifold for well testing, pipelines for crude oil and diluent, connecting to piping to/from the Main Station. The main hydrocarbon reservoirs are Miocene age sands of the Oficina Formation with average poro-perms of (35% &5,000–15,000 mD), respectively. Permeability variations are generally caused by variations in grain sizes. Sands are primarily medium grained, well-sorted unconsolidated quartz-rich sediments, with minor amounts of clay minerals. Reservoir sands consist of approximately 97% quartz, 2% clays and 1% heavy minerals.

This work reviews several typical intelligent well systems (IWS) completed, including a gas producer, oil producer, auto-gas lift oil producer, multilateral IWS producer, and horizontal openhole multi-isolation producer. For each case, the wellbore modeling, completion design, choking operation strategies, and estimated performance will be introduced.Case histories based on the analysis of the well modeling results at the design stage of the IWS completion, including well performance along with real-time data, will demonstrate:• Was value realized by using an IWS? • How did the IWS completion, downhole choking, and monitoring contribute to adding value in accelerating hydrocarbon production, managing production allocations, delaying or minimizing water production, increasing recovery, and decreasing CAPEX or intervention costs?In conclusion, this paper will show how modeling technologies were developed to derive the IWS well and equipment design such as tool selection, customized choking positions, erosion protection, and tubing movement estimation. It will cover lessons learned through our experience in intelligent well systems, including flow modeling, erosion analysis, tool selection, and crossover control, and how we expect the future movement of this technology. to evolve. SPE 124916This paper will review several installations of various applications with intent to address these issues. First, defining the requirements of the well and the purpose within the field, an analysis of how much of the expectations was met with discussion on future usage of intelligent well technology. IWS Experiences and Value RealizationThe benefits of installing IWSs have been described by many authors 1-4 . In summary, those benefits can be attribubed to two main categories: for the purpose of reservoir management, including accelerate hydrocarbon production, improved reservoir knowledge, and flexible control production and drawdown to increase ultimate recovery; and for the purpose of decreasing OPEX or CAPEX cost, where decreasing intervention cost is one of the typical applications especially in offshore operation. The following paragaphs give the descriptions of those benefits, based on our IWS case histories, available production and well test data, operator feedback, and theoretical modeling analyses at pre-completion design or post-completion stages.A large percent of the planned IWS completions are used to control a well that penetrates multiple production zones with commingled production. Obviously, accelerate production, produce marginal reserves, improve reservoir knowledge, and increase recovery are the main drivers for these IWS applications. Two-Zone IWS Gas Producer and Planning of Completion -Manage commingled production, adding flexibility in reservoir managementCompletion description. Fig. 1 illustrates a schematic of one completed two-zone IWS well with a dual flow path frac-pack system. Two downhole control valves are installed. The lower downhole control valve is shrouded and connects to a small outer-diamet...

Throughout the past decade, the reservoir management and interventionless flow control benefits of Intelligent Well Systems have made them a perfect fit for deepwater developments. Approximately 90% of current deepwater wells are subsea, and the number of subsea wells is expected to continue to grow. To enable subsea operators to reap the rewards of intelligent well technology, the industry (operators and service companies) is working to interface downhole intelligent well equipment with subsea trees and controls. Currently, the hydraulic penetration requirements of intelligent wells and the limited number of hydraulic penetrations in many existing subsea trees prohibit some subsea operators from using intelligent well technology. Manufacturing lead times for subsea trees and control systems are usually quite long. Rather than interrupt rig and operation schedules for an extended period while waiting for new equipment with more penetrations, operators often choose not to run intelligent well systems, and sacrifice the resulting benefits. This paper will address various technologies and methodologies that are currently available to enable operators to benefit from intelligent well technology in subsea wells with limited number of penetrations. The case histories covered will illustrate how it is possible to reduce the number of hydraulic control lines required to remotely operate downhole flow-control valves without sacrificing overall system reliability. Introduction The industry has generally defined Intelligent Wells as wells equipped with downhole remote flow-control devices used to open, close, or regulate flow from and to multiple zones without the need for well intervention. Furthermore, Intelligent Wells are usually complemented by downhole permanent monitoring systems which provide valuable information used in the decision making process for the control of production or injection. All these systems require multiple control lines and cables to link the downhole tools to the associated surface equipment which serves as the interface between the operator and the system. Subsea systems are employed in deepwater applications or in shallow water fields where the economics do not justify the construction of dedicate platforms to support the wells. In subsea systems, the wellhead and Christmas trees are installed on the seabed and are submerged in the water, hence the name "wet trees." Wet trees, just like the surface "dry trees," provide a means of controlling the wells through a series of valves, piping, chokes and other related equipment. Subsea trees can be manually controlled by divers (shallow water operations) or by remote-control systems by means of hydraulic actuators. These control systems can be on surface linked to the trees by means of dedicated lines in an umbilical or they can also be sophisticated electro-hydraulic multiplex systems mounted on the trees, controlled through a subsea electronic module. Electro-hydraulic multiplex systems are becoming more popular due to faster response time, increased reliability, and lower umbilical costs. These subsea control systems not only need to control functions on the trees, but also need to be able to interface with and control downhole equipment (i.e. safety valves, downhole chemical injection valves, permanent instrumentation, and intelligent well valves). Penetrations through the tubing hanger provide a means of communication between the subsea control system and the downhole equipment. Subsea control systems normally have two hydraulic circuits for controlling downhole functions: one high pressure (HP) normally dedicated for the safety valve and one low pressure (LP) normally used for the intelligent flow control valves.

Unfortunately, most of today's oil and gas fields are not located in our backyard, or in easily accessible locations for that matter. The "easy oil," as many call it, is long gone so now we are forced to explore new frontiers, from ultradeepwater areas, to the Arctic Circle, deserts, or deep inside tropical jungles. These remote and inhospitable environments present a series of logistical challenges to oilfield operators. Accessing these areas, establishing the necessary infrastructure, and mobilizing personnel and equipment required to operate an oil field can be costly, risky, and time-consuming. On the other hand, in today's modern business world, technology is employed on a daily basis to overcome geographical boundaries or obstacles and make us more efficient. Thanks to telecommuting, millions of workers do not have to drive to the office: the office comes to them. Thanks to collaboration through virtual teams, individuals do not need to work in the same physical space nor meet face to face to be able to accomplish tasks; which saves millions of dollars in cost and time associated with business travel. This paper presents a series of case histories demonstrating how intelligent completion and production systems can be used to apply the same telecommuting and virtual team concepts to solve some of the logistical challenges faced in today's remote oilfield operations. An outline of general considerations and recommendations is also proposed as a guide for individuals planning to implement these technologies.