PEH:Intelligent Well Completions
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume VI – Emerging and Peripheral Technologies
H.R. Warner Jr., Editor
Copyright 2007, Society of Petroleum Engineers
Chapter 3 – Intelligent-Well Completions
The generic term “intelligent well” is used to signify that some degree of direct monitoring and/or remote control equipment is installed within the well completion. The definition of an intelligent well is a permanent system capable of collecting, transmitting, and analyzing wellbore production and reservoir and completion integrity data, and enabling remote action to better control reservoir, well, and production processes. The concept of the intelligent completion does not generally refer to any capability for automated self-control but relies upon manual interface to initiate instructions to the well.
Remote completion monitoring is defined as the ability of a system to provide data, obtained in or near the wellbore, without requiring access and entry for conventional intervention to the well. Remote completion control implies that information and instructions can be transmitted into the well to alter the position or status of one or more completion components. The primary objectives of these abilities are normally to maximize or optimize production/recovery, minimize operating costs, and improve safety. As of 2002, there were some 80 intelligent-well completions with a variety of systems installed worldwide. Hydraulic motive power supplies predominate for these systems, although various hybrid electrohydraulic and optohydraulic completions have been successfully deployed.
Until the late 1980s, remote monitoring was generally limited to surface pressure transducers around the tree and surface choke, with remote completion control restricted to the hydraulic control of safety valves and (electro-) hydraulic control of tree valves. The first computer-assisted operations optimized gas lifted production by remote control near the tree and assisted with pumping well monitoring and control. Data are now transmitted to remote (from the well site) offices and interpreted, although such data handling and transmission procedures often leave much to be desired and reflect the ‘’ad hoc’’ nature of such installations (e.g., proliferation of standalone offshore personal computers, production monitoring system data overload, etc.). More recently, permanent downhole pressure and temperature gauges have increasingly been run as part of the completion system and combined with some form of data transmission infrastructure. The reliability of such systems is still variable, but on average is trending toward acceptable levels.
With the development, successful implementation, and improving reliability of a variety of permanently installed sensors, it was perceived that the potential to exercise direct control of inflow to the wellbore would provide significant and increased economic benefit. The service industry responded with early complex, high-cost systems designed to provide full functionality, which did not reach wide acceptance because of the perceived low probability of success and resulting high installation risked-cost. To counter these problems, industry responded with lower-cost hydraulic systems, which provided some of the functionality of the initial high-end devices. These “budget” systems permit a variety of sensors to be packaged together with the hydraulic control devices to provide a complete intelligent-well completion. Installations of intelligent-completion systems multiplied from 2000 to 2002 and are presently running at some 40 to 50 well systems per year. This level of application will increase as the technology becomes widely accepted as being demonstrably field proven.
Fundamentals of Technology
The long-term objective of the “intelligent-well system” is a well (or several wells) with the capability for automated self-control, without the need to enter or manually send instructions to the well, which implies a closed loop between monitoring and control devices. Downhole sensors and control devices would, therefore, be combined with a surface or subsurface unit for production optimization. Systems would be programmed to optimize a given parameter, such as net production, by varying, for example, the inflow profile from various zones or perhaps the gas lift rate. This programming could be reset remotely. Recent and developing remote monitoring and control capabilities include: multiphase flow measurement; chemical composition and sand detection; multiple sensors and flow monitoring; remote-control gas-lift valves, flow-control sleeves, valves, and packers; along-hole profile detectors for pressure and distributed temperature; and seismic geophones and resistivity sensors.
The following points reflect the general functional context of the intelligent well.
- The intelligent well forms part of the overall vision of reservoir management optimization and automation system.
- Fine-tuning of production will no longer be limited to the surface processes.
- Such wells will obviate or reduce the frequency of intervention required for reservoir and production monitoring and optimization.
- Ultimate recovery and production will be increased by zonal/branch optimization and timely remedial work.
- Gross fluid handling, waste, surface hardware costs (lines, separation, metering etc.), manpower and support services will be reduced.
- Depending on access, the completion is either permanent or easily retrieved. In the former case, the intelligent well must therefore be rugged and reliable.
Intelligent-well-development objectives for 2000 to 2010 are listed next.
- Prevention (of routine intervention for reservoir management purposes) rather than cure (reactive intervention) is the norm.
- Multiple horizon or reservoir penetrations per well are the norm.
- Self-optimization/automation of wells and facilities is the norm.
- Costly well intervention is the exception.
- Artificial-lift systems are designed for minimum intervention by reliability, backup, and ease of replacement of key components.
- Processes are designed on an optimum system rather than component basis (e.g., downhole/subsea vs. surface).
- Intelligent-completion-system reliability is seen to exceed 95% operability 5 years from installation.
As indicated, downhole intelligence may be linked to a wider intelligent network of wells and facilities via the field or process management system. This has been stated as a longer-term aim, enabling further optimization, reduction of costs, and manpower by automation of the production system.
Objectives of Intelligen-Well Flow Control
The value of the intelligent-well technologies comes from the ability to actively modify the well zonal completions and performance through flow control and to monitor the response and performance of the zones through real-time downhole data acquisition, thereby maximizing the value of the asset.
The oil/gas industry has only begun to realize the potential of intelligent-well technology to contribute to efficiency and productivity. Beyond the attraction of interventionless completions in the high-cost arena of subsea and deepwater wells, intelligent-well technology can deliver improved hydrocarbon production and reserves recovery with fewer wells. Intelligent-well technology can improve the efficiency of waterfloods and gasfloods in heterogeneous or multilayered reservoirs when applied to injection wells, production wells, or both. The production and reservoir data acquired with downhole sensors can improve the understanding of reservoir behavior and assist in the appropriate selection of infill drilling locations and well designs. Intelligent-well technology can enable a single well to do the job of several wells, whether through controlled commingling of zones, monitoring and control of multiple laterals, or even allowing the well to take on multiple simultaneous functions—injection well, observation well, and production well.
Finally, intelligent-well technology allows the operator to monitor aspects of wellbore mechanical integrity or the environmental conditions under which the completion is operating and to modify the operating conditions to maintain them within an acceptable integrity operating envelope.
Equipment and System Requirements
Intelligent completions combine the functionality of control and monitoring installed permanently within the wellbore. The control devices initially were based upon technology used by conventional wireline-operated sliding-sleeve valves. These valves were reconfigured to be operated by hydraulic, electrical, and/or electrohydraulic control systems to provide on/off and variable position choking. Further development has resulted in the choke devices being configured for high-pressure differential service and to some degree being resistant to erosional effects. Alternative equipment, again based upon existing subsurface safety-valve technology, has provided inline valves to give on/off closure. A combination of these control devices with multidrop pressure and temperature sensors has resulted in the concept of the intelligent completion being developed. Further sensors have been developed to provide flow measurement using either nonintrusive systems or venturi meters. Combinations of these devices now available link electrohydraulic systems with newly emerging fiber-optic sensors.
The findings of the Production Engineering Assn. steering group arrived at a standard communications protocol known as the Intelligent Well Industrial Standards (IWIS).  This standard will enable industry-wide development of equipment which can be more readily packaged and integrated into intelligent-well reservoir-control systems. Ultimately, cable-free systems will enable the greatest scope and flexibility for this technology in terms of cost, ease of installation (e.g., multilateral problems), and maintenance (retrievability). All-electric systems will allow the next step to downhole power generation; although there is concern over reduced reliability compared with traditional hydraulic control. Data transmission to and from the surface could be by several means. Electrical or optical conduits are currently the leaders for data transmission, but optical power transmission capability is extremely limited. The growth in electrical submersible pump (ESP) usage is being combined with control developments, using the significant downhole hydraulic power available.
Screening Criteria (Justification and System Design)
The potential for synergy between the benefits of various emerging technologies is discussed next. The applications and benefits of remote completion monitoring and control are obviously closely dependent on the type of well considered in each application. In particular, there are strong complementary benefits between multilateral wells and remote control, which will tend to accelerate the trend toward a relative increase in downhole investment in fewer, but more highly productive, wells. Conversely, it makes limited sense to install the bulk of any drainage network downhole if poor reliability leads to loss of control of reservoir management.
General benefits of remote completion monitoring and control are as follows:
- Improved recovery (optimize for zonal/manifold pressures, water cuts, and sweep).
- Improved zonal/areal recovery monitoring and accounting (locate remaining oil and define infill development targets).
- Increased production (improved lift, acceleration, and reduced project life).
- Reduced intervention costs.
- Targeted squeeze/stimulation treatments from surface.
- Reduced water handling.
- Downhole metering (possibly by zonal difference) may be less complex and expensive (cf. seabed/surface).
Design ConsiderationsThe basic method required for developing an intelligent-completion design involves the clear definition of a base-case operating philosophy that details the proposed well operating conditions and scenarios. This operating philosophy will detail the required control valve functionality whereby on/off or variable choking may be specified to meet defined injection or production criteria. Performing reservoir analysis using simulation techniques (Fig. 3.1) arrives at comparison between this base case and an intelligent-completion alternative. A revised production profile is generated using a well-performance simulator, and the overall project value determined by considering the incremental capital investment and change in revenue owing to enhanced oil production and the resulting changes in operating costs from reduced intervention.
In many cases, intelligent completions should be considered as part of the overall integrated production system. The functionality now exists to provide optimized gas lift control to improve lift gas usage efficiency, optimized offtake to control water cut at the reservoir interval level, and optimized water injection to enhance sweep to improve field oil recoveries. The processes can be linked to overall field management systems to improve operating efficiencies throughout the field.
Layered Reservoirs and Horizontal Wells
The comments discussed next apply to layered development wells and equally to horizontal wells intersecting several sub-blocks or with other lateral variation. The degree of control and monitoring, however, depends heavily on the type of completion installed (cemented, ESP, screen, etc).
At present, with conventional completions and surveillance techniques, accurate or even meaningful measurement of individual zonal properties is often impossible. The main factor is the interference between layers (pressure, crossflow, etc.). An intelligent-completion system allows temporary isolation of layers while surveys are performed. Zonal flow data may be obtained continuously from individual sensors or by controlling the position of the interval control valves to alter or isolate the flow from certain layers.
The routine conventional field management cycle of proposal, obtaining data, interpretation, then programming and implementing remedial action can lead to delays of months or even years before beneficial results are achieved. In some cases, the cycle may not even occur because of the costs and risks involved and the lack of a firm case on which to undertake the first step in the process (e.g., justifying a subsea intervention). Risks include damaging the well, inability to interpret data, and unexpected irreversible results from the remedial action. Remote completion control will allow zonal data to be obtained at no incremental operational cost and remedial action to be taken immediately in the form of zonal isolation, choking, or treatment. Changes to the well inflow profile can thus be temporary and adjusted for water breakthrough trends, manifold pressures, or surface handling constraints.
It is this form of monitoring and immediate/ongoing action that increases production and recovery. Three simplified horizontal-well reservoir-simulation studies by a North Sea operator concluded that the use of individual choke settings for different intervals (set to even out water breakthrough) significantly delayed the onset of water production and subsequent increasing water cuts. Given sufficient pressure support and zonal isolation, examples showed gains in recovery of 3 to 10% over 6 to 10 years.
The Osprey field typically employs upper or lower reservoir completions, with rig or vessel intervention required to isolate one and perforate the other. To optimize recovery, a reservoir interval will not be isolated until well into the high-water-cut “tail” period. Completions with remote zonal monitoring and control would allow early (temporary) isolation of the first interval at some point during its net decline and intervention-free opening of the second interval. As a minimum, this would result in production acceleration and intervention savings. An upside could be reservoir equilibration and improved recovery because of gravity drainage during the time the first interval was isolated. Intervals could subsequently be flowed combined (with the possibility of monitoring) or separately.
All of the comments for layered reservoirs and horizontal wells also apply to multilateral wells. Given the volume of reserves and importance to field development that may be associated with each branch, flow monitoring and control is probably of greater importance here than for a conventional well. Multilateral wells in which intelligent-completion devices are implemented are still in their infancy, although it appears possible to install up to six zonal control devices within the main wellbore. Initial completions would therefore have control at the mouth of each lateral. The flow restriction of the main wellbore compared to the available productivity of the combined branches is an issue for many multilateral wells, although the ability to isolate branches with high water or gas cuts is very valuable.
Injected treatments (scale inhibition squeezes, stimulations, water reduction) are also more problematic in a multilateral well. Remote completion control enables treatments to be diverted as required into each branch, if not into each zone. A choice is required between the installation of permanent control devices, while still enabling the ability to re-enter any lateral. At the moment, intelligent-completion systems are intended to remain in place permanently. One could argue for a requirement for a normally remote-controlled device that could be removed through tubing to facilitate the unexpected need for a branch re-entry. Until cableless systems or downhole mateable connectors have advanced significantly, this flexibility would probably reduce reliability to an unacceptable level. In wells where frequent branch entries are expected to be required, isolation or de-isolation of the branch can then be achieved by conventional methods during the well intervention. Well-monitoring devices may not necessarily interfere with re-entry and may also be made retrievable with less risk to system reliability and production performance.
It is already being seen that much thought must be given to the required functionality of multilateral wells before selecting a completion design. The availability of remote completion monitoring and control options makes this all the more important. Lack of forethought results in lost opportunities and/or potentially expensive and embarrassing future restrictions.
In addition to the direct production benefits possible by remote monitoring and control, reduced deferment and intervention cost savings will result from a successful system. For subsea operations, monohull vessels are providing a cheaper alternative to full rig intervention for certain applications; however, rising rig rates will also affect monohull charges, and a 3- to 7-day well intervention for surveillance or remedial action can still cost U.S. $500,000 to U.S. $1.5 million (typical North Sea rates, 2002). These costs are naturally amplified for ultradeepwater developments, where riser mobilization alone can generate costs on the order of U.S. $15 million. For platform wells, intervention cost will normally be much lower, but this may depend on the drilling sequence activity level, possibilities for concurrent access, whether the installation is normally manned, seasonal effects, and whether the installation is equipped with a rig.
In all cases, the economic benefits of intelligent completions must be balanced against alternatives, which in most cases are conventional completions operated with normal intervention techniques.
Engineering Issues (Interfaces and Integration)Metering requirements depend partly on the existing or planned seabed or surface facilities and on the relative merits of downhole installation. In general, the specification of an intelligent completion will result in a requirement for a data infrastructure to enable availability of data in a useable format. A typical data/control infrastructure is shown in Fig. 3.2. The extent of any downhole monitoring or metering must be justified on a well or field-specific basis.
Current industry pressure and temperature data specifications are summarized next.
Control Device Performance. For pressure buildup surveys, the requirement is generally for closure “as fast as possible” to obtain early buildup data (and fast opening for drawdown analysis). The speed of closure is in practice determined by the starting position, viable stroke speed (vs. power), and shock considerations. With a downhole zonal flow-control device, there is already the benefit of no wellbore-storage effect, and full closure is expected to be 1 or 2 minutes or less, depending on the starting position. Opening speeds may be limited by sand-production considerations. When no survey is being taken, wear and damage to the downhole device may be minimized by simultaneous operation of the surface choke.
Fiber Optics. Fiber-optic systems have been developed that enable direct conversion of downhole measurands into optical signals. A distinct advantage with fiber-optic systems is their effective immunity to temperature degradation. Early sensors deployed into steam injection wells in North America used thermal interaction with the optical fiber to generate direct distributed temperature traces. Development of resonating crystal optical pressure sensors produced a transducer that gave an optical output varying with pressure. These early pressure transducers were installed initially in an onshore gas well in The Netherlands and in the North Sea Gyda development. The first subsea installation of a fiber-optic sensor (including a subsea optical wet mateable connector) was completed in the North Sea Guillemot field.
Subsequent developments in optical sensors have resulted in the downhole deployment of fiber Bragg-Grating sensors configured within transducers to measure pressure, temperature, flow, and seismic data. Packaging and integration of optoelectronic conversion devices into electrohydraulic subsea-control infrastructures has been successfully completed and may be considered mature.
Near-Wellbore Sensing. Electromagnetic resistivity arrays have been successfully deployed into wells to monitor near-wellbore effects and determination of fluid-front movement. Integration of these sensors with automated sequencing of downhole control devices to provide enhanced waterflood control is now a short-term (if costly) option.
Field Development Aspects and Data Handling
Intelligent-completion technology has the potential to transform reservoir management techniques by reducing the cycle time inherent in normal operations in which conventional intervention for data recovery is only the first step to data analysis, decision making, and well reconfiguration introducing performance changes.
Operators are, however, challenged not only to justify the additional capital expense of intelligent-completion hardware but also to demonstrate an ongoing maximum value-addition of this technology to their asset. Data management, work processes, and engineering tools are prerequisites for realizing intelligent-completion technology value through improved asset management. Flow estimation and flow allocation are part of the foundation of asset management, and a variety of standalone sensors and/or numerical algorithms are available for flow derivation. The significant benefit of intelligent-well technology is realized when production information generated by downhole and field-deployed sensors can be actively and frequently used to optimize production and manage reservoirs with increased cycle frequency.
The service industry is addressing this challenge by developing, integrating, and implementing a suite of products that provides production data management, flow estimation, and flow allocation capabilities, and is driving toward the provision of intelligent-completion data and asset management tools in a Web-enabled environment. Technically, an Internet connection transmits real-time data from the wellsite to a central host. The latest in industry standards, including communication, security, data warehousing, and streaming protocols, are used. Statistical, nodal analysis and predictive modeling techniques are provided and are continually enhanced in the Web environment. These allow the petroleum professional to examine “what if” scenarios to quantify the effect of changes in reservoir conditions or well configuration and to recommend optimum settings for enhanced recovery.
Service companies are building expertise assisting the oil-producing companies to formulate the appropriate reservoir operations philosophy to translate the theoretical economic gains of intelligent-completion technology into reality. Data flow and management, work processes, and knowledge management techniques can be defined to enable the operator to fully exploit their intelligent-completion investment. This service takes the forms of a specific management project or an ongoing operational support service to implement reservoir management and well-performance optimization.
Intervention-Free CompletionsGiven the cost of higher capital expense, intelligent completions are designed for lifetime application, with overall materials selection being as important as the design of the more complex components. Not designing for retrieval can sometimes provide further opportunities to improve well integrity and reliability, for example by cemented annuli. However, given the current immature nature of many of the remote monitoring and control components, some form of recovery or intervention capability is prudent for the short to medium term.
Intelligent-completion installations are designed to fulfill specific operational requirements within severe environmental conditions (Table 3.1). In particular, scaling of wellbores can adversely affect the performance of control devices. Careful monitoring of the performance of these devices is required to determine any degradation such that regular exercising can be completed to maintain full operability. Again, in these environments, some degree of capability for mechanical intervention may be advantageous to reinstate the operability of seized (because of scale) control devices.
One faces a conflict between the concept of permanent remote control and the continuing perception (based on much experience) that a well must be designed for re-entry “just in case.” Emphasis on fluid rather than mechanical remedial treatments could minimize this conflict.
The following requirements are initially considered:
- The system must enable manual override via conventional intervention and re-establishment of flow.
- Components should be designed for the minimum pressure drop possible.
- Injection treatments should be possible without removal of components.
- Systems should withstand acid and scale treatments and not trap pockets of chemicals.
- Through-wellbore access is preferable, even if it causes a reduced well diameter, unless components are designed for easy removal and replacement (e.g., venturi flowmeter choke).
- All components must be assessed for likely mineral scaling pattern and remedial or preventative action (including stroking, magnets, and chemical treatments).
- All components must be assessed for vulnerability to sand production.
In the medium term, developments should aim for a special full-open setting of flow control devices to enable skin face treatments. Longer-term challenges include: opening of multilateral control devices to enable intervention/access into lateral; opening of inflow control devices to enable reperforating; and installation of control and monitoring devices into lateral wellbores.
Economic DriversThe chart presented in Fig. 3.3 demonstrates the relative values for different aspects of intelligent-completion application.
Certain risks are common to any application of a downhole control system, while others will be field-specific or at least increased or decreased by the given well conditions. Common risks include wellhead penetrator and cable/line failure, particularly during installation. Longer-term system failures may be caused by erosion (cables exposed across producing intervals and ports), temperature effects on electronics, wear and tear (dynamic seals), and seizure of moving components (including that caused by scale or production debris). Obviously, the simpler the system and the fewer moving parts, the fewer components are available to fail. Passive monitoring systems should therefore have better performance than an active control system. A balance must be found between careful control of moving parts (including movement against a pressure differential, etc.) and ensuring that systems are regularly cycled to avoid seizure. Procedures and supporting control software must be developed to ensure optimum system use.
Field Applications (Case Study Examples)
A discussion on complete screening exercises has proved to be the most convenient way to highlight intelligent-completion value and intelligent completion’s ability to enhance asset value in terms of production acceleration, increased ultimate recovery, and reduced operating expenditure (opex) and capital expenditure (capex). The following examples illustrate applications (and in some cases theoretical studies) that may be used as analogues to identify similar situations in which the appropriate reservoir conditions exist to justify the application of intelligent completions.
A Middle East operator was producing from a stacked pay sequence comprising multiple sands with good zonal separation (Fig. 3.4). The operating philosophy historically was to restrict production to the lowermost zone initially and, as production rates declined, isolate this zone and perforate the next higher zone.
Solution. Using production profiles supplied by an operator, a brief study determined commingled production rates and a revised production profile (Fig. 3.5). The study showed that no inflow control was required for commingled production and that zonal allocation could best be achieved by deploying a conventional completion enabling zonal testing by difference using conventional intervention.
Further enhancement (outside of the initial study’s scope) was identified in that the fractured carbonate structure could be controlled using a dedicated interval control valve (ICV) to permit intermittent production, enabling reservoir equilibration to occur during the shut-in periods.
Reduced Capex – Leveraged WellboreBackground. A second example is of a small oil accumulation (13 million STB) in the North Sea close to existing infrastructure. The exploration and appraisal wells were suspended subsea.
Challenge. Reservoir simulation showed that, after a short production period from the single production well, the pressure will decline to a point at which water injection is required to maintain reasonable production levels. The field economics would not support a production and water injection well plus related subsea infrastructure.
Solution. Following a quick screening exercise, several alternative development scenarios were presented to the operator, all showing considerable development capex reductions. The field-development scenarios were then ranked as follows (high to low capex):
Base Case. Drill and complete dedicated subsea producer and injector wells. Tie back the producer and install water injection infrastructure. (Capex is U.S. $74 million.)
Option 1. Eliminate the injection infrastructure by completing the injector well to permit dump flooding from an overlying aquifer using inflow control and monitoring. Cost savings of one tieback flowline for water injection. (Capex is U.S. $59 million.)
Option 2. Re-enter the exploration well and re-complete the well to permit dump flooding from the overlying aquifer using inflow control and monitoring. (Capex is U.S. $48 million.)
Option 3. As Option 2 (see Fig. 3.6), using multilateral technology, drill a horizontal drainage point in the top of the reservoir structure, eliminating the requirement for the production well. In addition, this reduces the subsea infrastructure considerably. (Capex is U.S. $37 million.)
Value. Without intelligent-completion technology, the project would not have been economic (i.e., the total development value of the project can be attributed to the application of intelligent completions).
Enhanced Recovery by Gasflooding
Background. A North Sea operator evaluated a prospect (based on a discovery from the late 1970s) for a subsea cluster development of a number of small accumulations tied back to an existing infrastructure.
Challenge. Development plans could not meet the screening criteria mainly because of the low ultimate recovery and, hence, small reserves from an estimated 850 million STB of original oil. Gasflooding had been considered to increase recovery; however, the nearest source of available gas combined with the cost of dedicated injection wells resulted in the base development option remaining uneconomic.
Solution. Using intelligent-completion technology concepts, deep high-pressure gas underlying the cluster development can be cross-produced via intelligent injectors into the oil zone during phase two of the development. The resulting gasflooding increases the ultimate recovery estimates sufficiently that the development prospect was deemed economic.
Value. Without intelligent-completion technology concepts, the project would not have been economic (i.e., the positive net present value of the project can be attributed to intelligent completions). The final selection of the gas injection method would be deferred until later in field life when the prevailing economic climate may dictate alternative gas sources.
Enhanced Production/Recovery – Internal Gas InjectionBackground. The next example is of a mature deltaic sand/shale oil reservoir with underlying gas accumulations.
Challenge. An operator in the Far East was experiencing rapid reservoir pressure decline in an oil-producing scenario.
Solution. A novel completion design (Fig. 3.7) was required to enable downhole transfer of high-pressure gas from an underlying zone while maintaining full control and monitoring. An approximately 20-psi pressure increase in the oil zone, over 3 months, resulted in enhanced production without the installation of capital-intensive water injection or gas re-injection facilities. For contingency, the completion was designed such that in the event the primary (gas injection) objective could not be achieved, then surface control would enable the well to be reconfigured into a gas production well.
Value. Subsequent production operations showed that oil production from a horizontal well located downdip from the gas injection well produced an additional 1,500 B/D when compared with the base case (noncrossflow) scenario. By extension, this development scenario is now being considered within other fields in the operator’s portfolio, permitting reassessment of the total asset value.
Intelligent Water InjectionBackground. A North Sea operator producing from a compartmentalized carbonate reservoir was required to ensure uniform water injection into multiple zones in a horizontal injector.
Challenge. The operator is required to determine zonal injectivity and select an intelligent completion to permit real-time downhole monitoring and flow control. The additional requirement was to permit detailed data acquisition for reservoir history matching.
Solution. A multizone electrohydraulic intelligent completion was installed, and water-injection rates were established and then equalized. The falloff pressure survey is shown in Fig. 3.8. Production enhancement was evident shortly after project commencement, and new development plans were initiated to take into account the revised injectivity data.
Value. The operator identified increased production in a nearby oil producer following operation of the intelligent completion to equalize water injection. Of great value was the information that Zone 1 had historically never received water injection because of poor injectivity (requiring hydraulic fracture of this injection horizon).
Production Acceleration by Zonal Control
Background. A North Sea operator producing from a stacked Brent sequence reservoir is required to use and control gas injection for improved sweep.
Challenge. The operator had previously experienced early gas breakthrough in the four-zone stacked oil play and was required to be able to selectively control inflow.
Solution. A four-zone electrohydraulic intelligent completion was installed that enabled zonal inflow control and pressure and temperature monitoring. Following completion, early gas breakthrough was indeed experienced, resulting in increased bottomhole pressure and decreased oil production from the other producing horizons. The high-rate gas zone was closed, and oil production was restored. Continuing control during the wells operational phase has permitted optimization of the oil production.
Value. The operator has completed a study in which simulation of the well performance without an intelligent completion was compared with the actual production data. The production acceleration equated to approximately 350,000 STB oil during the first 3 months of production.
As intelligent-completion technology matures, the field of application continues to expand to increasingly challenging environments such as the poorly consolidated, high-permeability, high-productivity, clastic reservoirs common to the Gulf of Mexico, offshore west Africa, offshore Brazil, and the North Sea. These areas fit the modus operandi of intelligent-well applications—high-productivity wells, complex reservoirs, high capital investment, and high intervention costs. The challenge of applying downhole flow control to these areas is their propensity to produce significant amounts of formation solids. At the best of times, sand production is not good for conventional completion equipment, and intelligent-completion equipment is faced with similar challenges. Although the condition of the intelligent-completion equipment may degrade to a state no worse than its conventional counterpart, its ability to do its job may be compromised. Erosion of choke elements, seal surfaces, control lines, and interference with device movement can render the intelligent completion inoperable, thus losing its functionality and the ability of the operator to use the equipment to realize its long-term value.
Sand-control techniques have been applied in these environments with varying degrees of success, and it is safe to say that a properly conceived and executed sand-control strategy can be very effective in reducing or eliminating solid production without unduly restricting productivity. New techniques, such as expandable screens, have been added to tried-and-true techniques such as gravel packs. But combining sand-control technology with intelligent-well technology can be a significant challenge, particularly when producing fluid from multiple, unconsolidated, high-productivity zones. The intelligent-completion industry is attacking this challenge in concert with the sand-control industry to generate innovative integrated solutions that bring maximum value to the customer.
Issues Specific to Applying Intelligent Wells
The challenge to the completions industry is how to effectively integrate intelligent-well technologies with modern sand-control strategies. The following issues must be considered when using intelligent flow control and monitoring in a sand-producing environment.
Protection and Isolation of Zones or Layers. Intelligent-well completions may be used to monitor and control flow from separate reservoirs, separate layers, or separate regions of a heterogeneous formation. Some or all of these zones may require some form of sand control, but critical to the effectiveness of the flow control is the hydraulic isolation of one zone from the other. Isolation may be achieved by using cemented and perforated liners with blank sections between zones. Openhole completions with screens or gravel packs may require blank sections of liner with inflatable external casing packers and multistage gravel-packing equipment.
Equipment Diameters and Available Space. Intelligent flow-control equipment, transducer mandrels, and flatpacks or control lines all take significantly more space than conventional completion equipment and may need to be deployed directly inside the sand-control equipment. This can create conflicts when attempting to keep casing and completion equipment sizes within conventional designs while maximizing flow areas to reduce flow velocity and maximize productivity.
Fluid Velocity, Pressure Drop, and Erosion. The bane of completion equipment in a solids-producing environment is erosion, and restricted flow areas and tortuous flow paths (typical around and through flow-control equipment) contribute to the effects of high velocity causing equipment erosion. When producing compressible fluids, such as gas, the flowing pressure drop associated with high velocity and restricted flow areas result not only in lower productivity but also in higher flow velocity. If the producing environment is corrosive, erosion/corrosion mechanisms must also be considered in the material selection for the completion.
Protection of Sensors, Cables, and Control Lines. Control lines, cables, and sensors represent the nervous and circulatory system of an intelligent-well completion, and damage to these elements may mean partial or total loss of the functionality of the intelligent completion. These elements must be adequately protected from erosion (or the potential thereof from sand-control failure), vibration, and thermal stresses by use of appropriately designed clamps and encapsulating blast joints. Some manufacturers provide systems using dual redundant control line and electronic systems capable of operating on one system in the event of failure of the other.
Mechanical Interference of Moving Components. The solids produced with the fluids can interfere with movement and sealing of dynamic components, particularly sleeves on flow-control chokes and valves. The design of these components must be sand tolerant—either they must exclude solids from entering cavities that may cause interference with movement, or they must be able to easily wipe away the solids or function despite the presence of solids. Actuators and spring returns must generate sufficient force to move the dynamic components despite buildup of solids or scale. Frequent cycling of the valves may prevent accumulation of significant amounts of solid but may also cause more wear and tear on seals and bearing surfaces.
Injection Wells. In multizone reservoirs where the production wells require sand control, sand control should also be considered for the injections wells. Dissolution of the natural cementing materials in water-injection wells can destabilize the formation. During shut-in of these wells, flowback and crossflow between layers at different reservoir pressures will result in significant production of solids into the wellbore, which can cause plugging and interference with flow-control devices. Closing the flow-control devices during shut-in to reduce crossflow will help alleviate the problem but may not prevent it.
Sand Control With Intelligent Wells
Use of intelligent-completion elements can significantly contribute to the management and prevention of sand production while maximizing hydrocarbon productivity. By monitoring actual inflow conditions and controlling and restricting fluid flow into the wellbore, intelligent wells can maintain the flow below critical rates that would otherwise destabilize the formation matrix or gravel pack. Zones that develop a propensity for water production can be choked back or closed in, also reducing the tendency for sand production aggravated by multiphase flow and aqueous dissolution of natural cements. One of the simplest solutions for controlling two zones with sand control is the dip tube or siphon tube solution. The well is completed with a conventional two-stage gravel pack (or screens), isolating the two zones from each other with a section of blank pipe and a packer. The completion is composed, top down, of the production tubing, feed-through production packer, gauge mandrel, ICV, a shrouded ICV, and dip tube with seal assembly which stings into a sealbore in the packer isolating the two zones. Production from the lower zone flows through the dip tube and through the shroud on the lowermost ICV, entering the production tubing through the lowermost ICV. Production from the upper zone flows in the annular area between the upper gravel-pack screen, in the annular area between the lowermost ICV shroud and the production casing, and enters the production tubing through the uppermost ICV. The gauge mandrel enables pressure monitoring of both internal and annular areas.
A second solution for controlling multiple zones with sand control is done where each zone is completed with (from top down) a hydraulic set, hydraulic feed-through isolation packer, a gravel slurry placement sleeve, a shrouded ICV with the shroud attached to the gravel-pack screen base pipe and the ICV attached to an internal, concentric, through-wellbore, production conduit, which ties into the isolation packer of the next lower interval. The gravel-pack slurry is placed with coiled tubing or a small work string stung into the sand placement sleeve, which acts as a crossover device for flow from the coil to the casing annular area for gravel packing, with returns back up the coiled tubing/tubing annulus. This completion can also be run with screens only, without gravel packing.
A limitation of the second solution is the limited flow area imposed by the multiple concentric strings and flow-control equipment. This solution is only practical with a production casing (liner) size of 9 5/8 in. or greater. A variation on this theme has been designed and tested in a proof of concept well wherein the ICV has been integrated with the screen base pipe; the base pipe becomes the main flow conduit, and the screen has been designed with increased standoff from the base pipe. Flow from the formation travels through the gravel pack, enters the screen, and flows in the annular area between the screen and the base pipe to the ICV, through which it joins the flow in the main production conduit. This solution provides an increased production conduit flow area. In both design cases, the relative flow areas between the casing and the screen, the screen and the flow tube (or base pipe) and up the main production conduit must be thoroughly examined to balance fluid velocities.
A third and most promising solution is the use of intelligent-well equipment with expandable screens. This solution maximizes flow areas in both the annulus and the production conduit. Installation of several dip-tube-type completions in the Gulf of Mexico has been successful. Two wells have been completed in the Allegheny field, while two other wells have been completed in the Typhoon field. One well in the King’s Peak field in the Gulf of Mexico was completed with a completion integrated with a multizone gravel pack. Additional similar completions are in the King’s Peak and the neighboring Aconcagua and Camden Hills fields. Five dip-tube-type intelligent completions have also successfully been installed in the Asia Pacific region. Of these completions, one combines a two-zone flow control system with a gravel-pack completion, and three are with expandable screen completions in the Champion West field. Those in the South Furious field use an internal gravel pack with an intelligent-completion expandable screen application.
The service industry and field operators are actively pursuing remote completion monitoring and control. Initial indications have indicated the benefits and scope for this technology, but only limited quantification of benefits has been made. Incremental initial well capital costs for intelligent-completion systems vary from U.S. $250,000 for a permanent downhole gauge system to U.S. $2.5 million for a multizone remote-controlled completion.
Based also on experience with manual intervention techniques, it is concluded that up to 10% of accelerated or incremental recovery is a reasonable target for this new technology in the early years of well life. Intervention savings provide further payback, particularly for subsea or unattended platform wells.
The author wishes to thank the following for their contributions to this section: Leo Koot, Derek Mathieson, Michael Konopczynski, as well as WellDynamics Intl. for data and material for input. Case study data have been supplied by Norsk Hydro, Maersk Oil and Gas, Brunei Shell Petroleum, and Shell U.K. Exploration and Production.
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SI Metric Conversion Factors
|bbl||x||1.589 873||E – 01||=||m3|
|psi||×||6.894 757||E + 00||=||kPa|