An Offshore China/South China Sea operator wanted to optimize the use of a rotary steerable drilling assembly, simplify and reduce operational steps, and provide a larger reservoir wellbore. The operator elected to drill a single 8.5" wellbore and, in order to address a variety of issues and potential problems, change from a Cloud Point Glycol Drilling Fluid to a Drill- In Fluid (DIF) at the reservoir entry point. A reverse sequence solution engineering process was employed wherein planning began from the point of view of a completed well.
Effectively addressing numerous potentially compromising elements within a plan to optimize both reservoir production and utilization of new drilling technologies can be achieved through Reverse Sequence Solution Engineering (RSSE).
Reservoirs with shale layers can cause serious problems during drill-in and completion operations. Reactive shales can lead to borehole instability during the drilling phase and, if not controlled, may plug gravel and screens in the completion phase. Further, DIF return permeability and lift off properties may be seriously impaired, resulting in reduced hydrocarbon production. Without properly sequenced well planning and fluid design, high rates of filtrate invasion, circulation losses, differentially stuck pipe and low production rates may result.
In order to minimize forming or accumulating unforeseen problems while a project is underway, it is sometimes critical to originate the planning sequence from the point of view of the desired end result. This paper attempts to provide an overview of a RSSE approach, which allowed incorporation of numerous new ideas, products, processes and technologies into an existing successful process. In addition, the details from a successful field test using the new elements will be presented.
The operator had drilled a total of 12 wells culminating in horizontal sections in a variety of sandstone reservoirs at depths varying from 2000 to 3000 m TVD, with the deeper wells reaching nearly 4200 m MD. Of these, 4 were new wells while the remaining 8 were sidetrack re-entries. In all sidetrack cases, whipstocks were set inside existing 9.625" casing, and 8.5" sidetrack wellbores were exited from the casing. These 8.5" holes were drilled to designated reservoir entries, culminating at or very near a 90° angle. Then, 7" liners were run to isolate the entire 8.5" tangent wellbore. On some of the wells, following hanging and cementing the liner, 7" tiebacks were performed. The wells were then drilled horizontally into the reservoirs with conventional directional drilling assemblies using a water-based DIF containing a calcium carbonate bridging component. Depending upon reservoir characteristics, completion methods varied from open hole completions, to slotted or perforated liners, to pre-packed screens.
The operator had accumulated a history of consistently exceeding hydrocarbon production expectations when the reservoir was drilled using a specifically engineered DIF. Not surprisingly, the operator wanted to retain this DIF component in future wells.
Ten of the 12 wells, including all the sidetracks, were drilled with a platform rig that had initially been designed for workover purposes only. As a result, the rig was pushed to operational limits in drilling mode, with the primary limitations being overall string weight (top drive, draw-works and mast), pump pressure and output, top drive torque and speed, fluid handling and mixing capabilities, as well as fluid storage and circulating volume (Figures 1 and 2).
Regardless of these limiting factors, drilling progressed, with the directional profiles, depths and step outs reaching very challenging levels.
Well control has always been a very important issue in the oil and gasexploitation business, since it involves money savings, people safety andenvironment threatening. The advancement of the exploration frontiers fromonshore to offshore fields, particularly, deep and ultra-deep waters, hasincreased even more the relevance of kick control and blowout prevention duringdrilling operations. Widely used drilling practices have been optimized andre-evaluated, so have new technologies been developed to handle specific issuesrelated to deepwater drilling operations, such as reliable and efficient wellcontrol practices. This effort has great importance to some countries likeBrazil, which have most part of their oil and gas production (close to 75%)concentrated on offshore wells, about 70% of those reserves are located in deepwaters. Regarding such scenario, this article presents a comprehensive anddiscussed literature review about well control in deep and ultra-deep waters,covering the evolution of the analytical and numerical kick models. Amathematical model has been developed to predict the pressure behavior insidethe annulus during a gas-kick circulation out of the well in deep waterscenarios. Considerations regarding the effects of wellbore geometry,frictional pressure losses, influx expansion, and two-phase flow models havebeen implemented in the present model. The analysis of the effect of someimportant parameters in well control in the surface pressure, such as the pitgain, water depth, mud density and pump flow rate are presented.
The exploitation in deepwater and the development of concepts related tothis activity has been changing a lot throughout the years. In the sixties, forexample, the exploitation and the development of offshore fields used to berestricted to 150 ft water depth. Nowadays, depths up to 1,300 ft areconsidered as deep water and above 3,300 ft are considered as ultra-deepwater.1
Particularly in Brazil, about 75% from the national production come from theCampos basin, in the north coast of Rio de Janeiro, with more than 70% of thosereserves located in deep and ultra-deep waters. 2 Deep waterdrilling in Brazil was stimulated by the discovery of the Albacora field, in1984, in a water depth that varies from 1,000 to 6,500 ft. In 1985, Marlimfield was discovered with the well RJS-219, in 2,750 ft water depth. In 1994,the Marlin-4 well (3,400 ft water depth) was completed and its production wasstarted. In 1996, the giant field of Roncador was discovered, with water depthsvarying between 5000 and 10,000 ft. The brazilian record of water depth is the1-RJS-543 well, located at Roncador field, reached in November 1999 in a9,300ft water depth.
In deep water drilling operations, an accurate control of all the drillingparameters, added to a detailed project and program are factors of extremeimportance in the environmental, economic and security aspects. A permanentconcern in these operations is the control of kicks and the prevention ofblowouts.
The first mathematical model of kick circulation was proposed in1968.3 The model disregarded the friction pressure losses in theannulus, the slippage speed between the gas and the mud, with a uniform annuluscapacity and the gas insolvable in the mud.
The model of Ref. 4 incorporated the effect of friction pressure losses inthe flow inside the annulus. Even though there was an improvement regarding theprevious model, it presented results that did not match field data,properly.
Hardbanding materials are used to protect tool joint drillpipe against wearin drilling operations. Hardbanding shall resist wear in openhole conditionswith a minimum damage to upper casing. Laying down drillpipe for hardbandingrepair can significantly increase rig time and tubular costs. All hardbandingproducts applied for Sincor were wearing out completely after drilling 15,000ft in 50 hours in the reservoir. It was necessary to search for new hardbandingalternatives with an extended lifetime. A field evaluation program was designedto compare wear resistance of different commercial hardbanding materials and toevaluate new techniques for welding tungsten carbide pellets with alloyingwires and for testing of tungsten carbide spheres being laser applied.Hardbanding products were selected upon analysis of wear mechanisms occurringin drillpipe while drilling horizontal wells in Sincor. Wear resistance wasmonitored in terms of cumulative drilled footage until gauging complete wear ofhardbanding on tooljoints. One of the newly developed hardbanding products wasfinally selected as the best option after considering its superior wearresistance, minimum expected casing damage, and moderate cost. This is thefirst reported successful application of tungsten carbide pellets welded withina hard matrix provided by an alloy wire for hardbanding purposes.
Wear of drillpipe is an important issue for drilling operations in Sincorarea. Wear increases operational cost due to repair of components, rig time tochange out worn down components, and lost of valuable tools. Wear of componentshas been reported in the tool joint drillpipes since start of operations.Hardbanding and repair cost for a 5,000-ft string can reach up to US$ 150,000over the string lifetime. With this amount of money and time invested in wearcontrol, high consideration was given to develop material specifications forrequesting wear resistant materials. Other solutions implemented in Sincor toreduce drillstring wear are the following:
Use of down-hole tools, i.e. Hydroclean drillpipe, for better hole cleaningand a consequently reduction of the backreaming while drilling horizontalsections.
Optimization of drilling practices such as mud circulation, use of Hi-Vispills, and backreaming parameters.
Use of mud additives, i.e. Ecolane solvent, and heating the mud to reducedrillstring friction.
Use of several types of hardbanding materials.
This work is aimed to find the most appropriated hardbanding material forprotecting drillpipes in openhole conditions. Minimum casing wear andenvironmental pollution due to chromium discharge within the drilling fluidswere identified as special concerns.
Sincor is an operating oil company created in 1997 and it is comprised byTotal Venezuela S.A., PDVSA Sincor S.A., and Statoil Sincor A.S. The companystarted operations in 1998 to exploit the Zuata reservoir located in theOrinoco Belt in Southeastern Venezuela. Reservoir is characterized by an 8-°APIheavy crude oil in unconsolidated sand with extensive shale bedding. Wells aredrilled in clusters to minimize environmental impact. Each cluster has anaverage of 12 extended reach wells having an average horizontal section of4,450-ft in length. Frequent backreaming is required for hole cleaningpurposes. This combination of unconsolidated sand and repeated backreaming asdepicted in Figure 1, are the primary causes for wear of drillstringcomponents. Drillpipe is laid down when tooljoint outside diameter is lowerthan 6-3/8".
Knowledge capture, distillation, preservation, and sharing among project teams are challenging issues across widely distributed organizations. The teams need to share information, learn about and apply best practices and lessons learnt, in a structured, easily accessible manner: anytime and anywhere. The implementation of a project management system integrating worldwide, web-accessible organizational-learned knowledge hub is presented in this paper.
A Project Knowledge Portal (PKP) was implemented; containing links to corporate web based knowledge hub, including a structured repository for all project critical information. The Integrated Project Management system (IPMS) was developed as a process matrix, based on a company wide implemented standard. The PKP uses the IPMS to create an ISO 9001 compliant structure behind all applied project processes.
Organizational knowledge is generated, captured, distributed and preserved throughout every stage of the project. The team uses the PKP to create a one-stop-shop for project knowledge. The project specific management system is stored in the Project Hub together with all associated documentation such as standards, procedures, manuals, roles and responsibilities, audit and review systems, records, etc. All project members have access to the management system anytime. The records of the system are generated by team members and posted into the Project Hub. The required changes to the system are made via the Project Hub to the project member that maintains project specific management system.
Knowledge Management (KM) components of the web based PKP include real-time synchronous and a-synchronous E-collaboration tools to capture decision processes and have an audit-able trail for document control. The Portal includes a static filing repository in the form of the Schlumberger Knowledge Hub. QHSE Data, Lessons Learned and Best Practices are captured and made available for the rest of the organization. An example of implementation is presented in an actual project, with details of the roles and responsibilities and the impact on organizational learning.
Managing complex reservoir projects involves many challenges and issues. Integrated Reservoir Management and Optimization (IRO) and their components have been discussed in a number of references.1,2 In order to successfully and effectively manage IRO projects, to reduce costs and to introduce new technology appropriately, these projects should not only involve the asset team, but a number of experts widely distributed geographically. The asset team should also be able to capture the relevant knowledge and best practices that are also stored geographically. This brings the challenges for "Time Management" - real time interaction and synchronization, "Process Management" - synchronization of multi discipline teams with defined processes, and "Knowledge Management" - effective management of knowledge (knowledge capture, usage, mining, transfer). Knowledge management and transfer is also becoming a main issue with the current age and experience distribution in the Oil&Gas industry.
There are currently four basic collaboration scenarios: conferencing (personal, video), paper, email and web based. Increased complexity of the tasks, the organization and the disciplines, combined along with information overflow makes these collaboration tools ineffective. The project knowledge portal (PKP) that incorporates an Integrated Project management system and the collaboration framework, which is explained in this paper, is introduced as a solution for this challenge.
A unique test procedure and a novel test facility have been developed for experimental determination of the adhesive-cohesive bond strength (ACBS) and the adhesion-cohesion modulus (ACM) of mudcakes formed by different mud systems. The test set up consists of a Wykeham Farrance stepless compression machine to embed a cylindrical foot up to a particular depth of the mudcake matrix and then to apply a pulling force to unstuck the cylindrical foot from the mudcake matrix, a digital dial gauge to register the depth of embedment and upward displacement during loading and unstucking process, an electronic balance to register the driving/pulling force during embedment and pulling stages of the test as a function of displacement, a lab jack to elevate the mudcake to a desired height and a PC-based automatic data acquisition system to record the data and monitor the test.
Experimental results indicate significant variations in ACBS and ACM of mudcakes for an identical depth of embedment depending on the composition of the mudcakes. The magnitude of the pulling force and the shape of the force-versus decrease in embedded area curve are influenced by adhesive and cohesive bonding potential of the mudcake material and the nature of the adhesive and cohesive bonds. The presence of electrolyte significantly influences the metal to mudcake and mineral to mineral bonding. The hydrated ionic diameter of the cations also has some effect on the adhesion and cohesion properties of mudcakes. The presence of barite within the mudcake matrix causes a significant increase in ACBS and ACM of the mudcakes probably due to the filler and mass adhesion effects of barite particles along with the molecular forces of interactions. The effect of three fluid loss additives such as modified starch, CMC and PAC on the ACBS properties of NaCl-Bentonite mudcakes has also been investigated. The presence of CMC and modified starch in NaCl-bentonite muds has little effect in the ACBS and ACM of NaCl-bentonite mudcakes. However, the presence of PAC in NaCl-bentonite mudcake causes some increase in ACBS but a significant reduction in ACM. The results of the test could provide useful information regarding bonding potential of different mudcakes to drill pipes, reamers, stabilisers and drill bits and also drill cuttings in case of cuttings bed formation in directional and horizontal wellbores. The test method can be used for mechanical screening of drilling mud additives and the results can be used in designing drilling muds to produce desirable mudcake quality.
The analysis of accidents over the past 20 years reveals the reasons why accidents happen and give valuable indications on how to prevent accidents in the future.
In a 20 year history, collection and evaluation of accidents which happened to employees of Weatherford Oil Tool GmbH, Germany, depending on the German legislation only "Lost Time Accidents" are recorded. "Non Lost Time" - and "Near Miss Incidents" will be mentioned at the end of this study.
Our goal is of course to reduce the number of accidents to zero. The way will still be difficult, steep and slippery but many reasons count to make our utmost efforts to achieve that goal.
Accidents are not only painful or even tragic for the person involved and his family but also a general loss of income and money by lost time, cost of illness, insurance and indirect costs, for the public as well as for the company. Therefore, the SCC (Safety Certificate Contractors) regulations which have been in practice for two years require a certain accident rate not to be exceeded.
The purpose of this study is to analyze the accident reasons broken down to the lowest level, define the focus points and from there develop ways, instruments and methods to really achieve zero!
Weatherford Oil Tool GmbH is a manufacturing and service company near Hannover, Germany. The manufacturing plant develops and assembles rig mechanization equipment and power equipment as well as mechanical cementing products (centralizers). The number of employees in the manufacturing facility is 155 (including administration). Also included in the legal entity of the company is a service station providing services such as well installation services (casing and tubing running services), fishing and window milling activities and completion services, with a total of 240 employees. Additionally there are 22 employees working for sister companies abroad.
The statistical summary starts in the year 1981 and is consistently followed until now. The data collected comprise the following subjects:
Number of "Lost Time Accidents" per location (Fig. 1):
Manufacturing plant Langenhagen
Operations foreign countries
The number of accidents per year declined from 33 in 1982 to 7 in 2001.
Number of employees per location (Fig. 2)
The number of employees changed from 380 in 1982 to 240 in 2001. The number of accidents must be considered in relation to the number of employees.
Part of body injured (Fig. 3): Arm; hand; foot; leg; head; body; spine.
Kind of injury (Fig. 4): Permanent damage; cut; fracture; strain; bruise; contusion.
In a corrosive downhole environment, the service life of a completion can beseverely reduced if suitable precautions are not taken. Pipe made of corrosionresistant alloys (C.R.A.) is used to minimize corrosion. Recently, steelmanufactures have developed modified corrosion resistant alloys (C.R.A.),specifically derivatives of Cr13, that are characterized by a black smoothscale surface on the outside of the pipe.
When these so called "Super" or "Hyper" alloys were first used, occasionalslipping was reported by field personnel. Fortunately no string was lost and noinjuries occurred, however, precious rig time was lost in resuming safeoperations. These slippages occurred with various inserts and with all types ofslip-type elevators or spiders.
An investigation carried out by the University of Hannover revealed that thesurface scale on the pipe had a hardness of over 60 Rc. Even insertsspecifically designed for C.R.A. pipe that use special gripping elements, suchas the Micro-Grip™ system have a hardness that is only slightly higher thanthis surface scale. Using conventional wedge type spider and elevator systemscan lead to slippage under certain load conditions, if no special precautionsare taken.
Based on these results and on the operating principles of wedge type spidersand elevators, a new Compact Spider/Elevator was designed. This device can beeither air or hydraulically operated and puts an additional downward force ontothe slip, as much as 40 tons for the hydraulic version, so that a firm grip isassured. In addition to conventional steel inserts, the device can be equippedwith so called Micro-Grip™ inserts, a gripping system that distributes therequired load equally onto a large number of small peaks. This minimizes theindentation of each single peak and thus, as previous research and fieldexperience has shown, preserves the surface integrity of the pipe with regardto corrosion [2, 3, 4]. The device can be run flush-mounted, further enhancingsafety on the rig-floor.
In a corrosive downhole environment, the service life of a completion can beseverely reduced if adequate precautions are not taken. This is especially trueof tubular material made of corrosion resistant alloys (C.R.A.), which is oftenused to minimize corrosion. Due to the great variety of downhole conditionswithin a production well such as temperature, dissolved and undissolved gasesand their depth-dependent partial pressures, an optimal corrosion protectionsystem requires comprehensive planning. Analysis of the downhole conditionsleads to the selection of the appropriate material to assure the best lifetimeunder the corrosive environment present.
The pipe manufacturers have reacted to the special requirements of theoperating companies. The main component used to improve the corrosionresistance of an alloy is the addition of chromium. C.R.A. alloys with up to 13% percent chrome content are commonly used and occasionally the content ofchrome is higher to cope with special corrosion conditions.
Conventional spider and elevator inserts cause die marks that can promotecorrosion. A gripping system named Micro-Grip distributes the required loadequally onto a large number of small peaks, minimizing the indentation of eachsingle peak.
As underbalanced drilling and intervention operations find offshore applications, development may be restrained by physical dimensions, operational delivery and logistics preventing the wider application of the technology and maintaining the conventional methods with its higher cost base.
The first generations of Nitrogen Membrane units were large stand-alone skids that had no built-in compression and booster capability; these were supplied in separate units. For land-based use in drilling, well intervention and pipeline applications, this presented no problems since space availability was not an issue. However for offshore use where space is at a premium, these additional components presented such a large footprint that their use was difficult in most applications and impossible for smaller jack-up rigs and production platforms, where deck space and loading are major limitations.
In order to facilitate the use of Nitrogen Membrane technology in offshore environments, it was clear that a new generation of units would be needed. Initial development centered on existing land-based units, with primary and booster compression, Membrane and cooling combined in modular two-piece units. This approach provided for a smaller footprint, but lower output per square foot of space occupied and higher individual weights. This output penalty could be made up with additional units but the space occupied was prohibitive. Subsequent development efforts were based on a three-piece unit with prime mover, primary compressor and secondary booster driven in-line through a single drive shaft. A second-generation Nitrogen Membrane unit, with increased output and efficiency, and the cooler skid, were top-mounted on the three-piece unit. A third generation unit is currently in the design and development stage, which will be fully compliant with all offshore regulations for North Sea operations.
This paper will review the existing technology of Nitrogen Membranes. It will detail the development and design of the second and third generation units on which all the major concerns such as performance per weight/area, access, zone and operator compliance requirements and safety were addressed. It will also review all the stages of the developments, the design, manufacture, testing and field problems encountered and the lessons learned from them.
Some wider application of the technology will also be demonstrated due to the improved technology and the cost savings through operational efficiency highlighted.
As underbalanced drilling (UBD) and well intervention operations find offshore applications, physical dimensions, constraints, operational delivery and logistics may restrain development. This has prevented the wider application of the technology and has resulted in the continued application of conventional methods with their higher cost base, lower rates of penetration (ROP), and greater risk of formation damage.
Cryogenic nitrogen has been used on numerous projects, but for conventional underbalanced drilling applications the logistics and economics of maintaining sufficient nitrogen supply is prohibitive. Generally cryogenic nitrogen has only proven itself as a viable offshore alternative on the smaller well intervention operations.
In the Saudi Aramco gas campaign, during the last few years, a high casing-casing annulus phenomenon was observed clearly days or months after rig released. Some of these casing or liner set and cemented across abnormally pressured formations, which contains salt water, gas or combinations of both. These zones were cemented using various cement density ranging from normal to high-density slurries.
The integrity of cement sheath is commonly measured by its ability to provide long term zonal isolation, at the time of completion and for the life of the well. It also has to physically support the casing, withstand pressure cycles, temperature cycles and protect the casing against corrosive fluids. Not all cement applications perform these functions with equal success, and many of those that do, they do not stand up against the forces that exert upon them during time.
This paper is evaluating the expansion and the shrinkage property using class "G" cement in Saudi Arabia, and its effect on the cement matrix. One of the potential problems causing the failure of cement zonal isolation, can be attribute to the over use of chemical expansion additives. The cement bond failure can cause migration of fluid from one zone to another, losses of reservoir fluid, well control issues and poor stimulation operations.
High casing-casing Annulus (CCA) pressure is an alarming sign during Gas well production life, from safety point of view especially if effluent is hydrocarbon base fluid. Its presence could also impose operational limitations, which could easily hinder the well productivity or even force the operator to consider an expensive work over on emergency basis. Eliminating the CCA pressure is one of the objectives of every cement job during the design phase and prior to the physical placement. The slurry design and placement procedure are the key factors to long term cement job success which can be measured by the zonal isolation, Lack of micro-annulus and the cement sheath integrity during the well life. The cement sheath defects and failure to seal a pressurized fluid containg zone is usually refered to inadequate mud displacement, annular fluid migration and possibly mechanical factors. Few cement specialists consider the failure of cement sheath integrity as primary reason for CCA to exist.
Unique cement sheath failure was observed during the early stage of gas wells in Saudi Fields. This was indicated by the presence of high CCA pressures with effluent presenting deep formations. Such incidents drove to a study to evaluate the possible source and path of this effluent to prevent the re-occurrence if possible. It was found that for CCA pressure to appear at surface the effluent should pass several barriers over thousands of feet such as cemented casing / open hole annulus, cemented casing /casing annulus and external casing packers. These lead to possible causes such cement design, placement procedure, and liquid to solid transition control and post placement well environment.
Among all of the above the cement sheath failure "cracking" and cement design was most logical issue to re-consider due to the similarity feature of expansive cement which focused the study on the expanding property of cement during the post placement and side effects if any.
When cement is correctly placed in the wellbore and provides initially a good zonal isolation, the zonal isolation often disappears overtime, which in most cases is caused by micro annulus or reduction in cement permeability.
Expansive cement systems have been advocated for use across formations, where micro-annulus is the primary cause of formation's fluid migration. Controlled expansion, through the modification of the additive concentration, will assist in sealing small gaps between the cement and the casing or formation, even though expansive cement undergoes a bulk dimensional expansion, they still exhibit a net chemical shrinkage and the same hydrostatic pressure decrease as normal cement. This is possibly ineffective in controlling or sealing large channels and washouts.
Intelligent well completions have introduced a step-change technology that improves project economics by permitting the operator to actively manage the reservoir. This aspect of asset management is especially important in those wells requiring sand control, often located in remote geographic locations or extreme operating environments, such as deepwater and ultra-deepwater, where the reserves base is high and the subsurface complex. Combining sand control technology with intelligent well technology can be a significant challenge, particularly when producing fluids from multiple, unconsolidated, high productivity zones.
To-date, the successful intelligent well completions that have been completed with sand control have been limited to a maximum of two productive intervals with full time monitoring and control. The limitation has been a result of the architecture of a gravel packed completion, requiring that the interval control valves (ICVs) and pressure and temperature gauges be placed above the zones of interest. While valuable to the asset where employed, some operators have expressed a need to have the control and monitoring equipment placed at or in the completion itself, or to have the capability of adding additional sand control completions to the wellbore.
Design solutions exist that may permit the operator to stack three or more gravel packs in a single wellbore and achieve full intelligent completion functionality. This paper will discuss those solutions and present several examples and case histories.
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, Australia and the Asia Pacific region, 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.1,2,3
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 as the induced damage may potentially lead to safety, environmental and financial consequences. 4 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 long term value.
Sand control techniques have been applied in these environments with varying degrees of success; however, 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 conventional techniques such as gravel packs and frac 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.